UNITED STATES GOVERNMENT MEMORANDUM

To: Public Information (MS 5030)

Plans Section, Office of Field Operations (MS 5231)

Public Information copy of DOCD

Control # - S-07614

Type - Supplemental Development Operations Coordinations Document

Lease(s) - OCS-G08035 Block - 574 Atwater Valley Area

Operator - BHP Billiton Petroleum (GOM) Inc.

Well SS003

DP Semisubmersible or Drillship

Attached is a copy of the subject plan for public comments on issues that

should be addressed in an Environmental Assessment.

It has been deemed submitted as of this date and is under review for approval.

Ronald O'Connor

Plan Coordinator

G08035/AT/574 5201 FSL, 2999 FEL G08035/AT/574 WELL/SS003 Botm Lse/Area/Blk Surface Location Surf Lse/Area/Blk Site Type/Name Description -

Rig Type - Subject: From: December 23, 2013BHP Billiton Petroleum (GOM) Inc. 3 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 These regulations may be further clarified by Safety Alerts, and current policy making invoked by the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEM), Environmental Protection Agency (EPA) and the U.S. Coast Guard (USCG).

The appropriate life rafts, life jackets, ring buoys, etc., as prescribed by the U.S. Coast Guard will be

maintained on the MODU at all times.

BSEE is required to conduct onsite inspections of offshore facilities to confirm operators are complying with lease stipulations, operating regulations, approved plans, and other conditions; as well as to assure safety and pollution prevention requirements are being met. The National Potential Incident of Noncompliance (PINC) List serves as th e baseline for these inspections.

BSEE also inspects the stockpiles of equipment listed in the Operator's approved Subregional Oil Spill Response Plan that would be used for the containment and cleanup of hydrocarbon spills and is further addressed in the “Oil Spill Information” section of this Plan.

In accordance with Title 30 CFR 250.1501, the goal of our training program is safe and clean OCS operations. To accomplish this, BHPB ensures that our employees and contractor personnel engaged in well control understand and can properly perform their duties.

Supervisory and certain designated personnel on-board the facility are to be familiar with the effluent limitations and guidelines for overboard discharges into the receiving waters, as outlined in the EPA’s NPDES General Permit GMG290000. Some of these pollution prevention measures include installation of curbs, gutters, drip pans, and drains on drilling deck areas to collect all contaminants and debris.

All discharges related to the operations proposed in this Plan are covered under EPA’s NPDES General Permit referenced above. BHPB’s permit number is GMG290184.



### (d) Storage Tanks and Production Vessels

Tanks with a capacity of 25 bbls or more of oil as defined at 30 CFR 254.6 is listed below:

Type of Storage

Tank Type of Facility Tank Capacity (bbls) Number of

Tanks Total Capacity (bbls) Fluid Gravity (API)

Lube Oil Tank P / S Drillship – CRL 661 2 1322 29-39 o

Dirty Oil Tank AFT Drillship – CRL 296 1 296 29-39 o

Dirty Oil Tank FWD Drillship – CRL 69 1 69 29-39 o

Diesel Oil Drillship – CRL 8549(2); 7906(2); 3736(2); 2665(2); 290(2); 775(4) 12 49,392 29-39 o

Base Oil Drillship – CRL 3541 1 3541 29-39 o

Type of Storage

Tank Type of Facility Tank Capacity (bbls) Number of

Tanks Total Capacity (bbls) Fluid Gravity (API) Fuel Tanks (005, 006, 007, 008) DP Semisubmersible DD-1 5107 4 20,428 29-39 o

Fuel Tank (009) DP Semisubmersible DD-1 3003 1 3,003 29-39 o

Fuel Tank (010) DP Semisubmersible DD-1 2585 1 2,585 29-39 o

Fuel Tank (011) DP Semisubmersible DD-1 5228 1 5,228 29-39 o

Base Oil DP Semisubmersible DD-1 3541 1 3541 29-39 o 

# A men d ment

# bhpbillito n

:'f'ir f !IF > futur e

BH P Billito n Petroleu m (GOM ) Inc

. 136 0 Pos t Oa k

Boulevar d Suit e 15 0

Housto n Texa s 77056-302 0 US A

Te l 71 3 96 1 850 0 Fa x 71 3 49 9 599 4

www.bhpbiiiiton.co m

Mays

, 201 3

Mr

. Bo b Sebastia n Regiona l Superviso r fo r Leasin g an d Plan s
U.S

. Departmen t o f th e Interio r

Burea u o f Ocea n Energ y Managemen t

120 1 Elmwoo d Par k

Boulevar d

Ne w Orleans

, L A 70123-239 4

ATTN : Plan s Uni t

RE : Supplementa l Uni t Developmen t Operation s Coordinatio n Documen t (DOCD )

Atwate r Valle y 57 4 Uni t (Agreemen t No

. 754395004 )

Leas e OCS- G 08035

, Atwate r Valle y Area

, Bloc k 574

, Wel l SS00 3

OC S Federa l Waters

, Gul f o f Mexico

, Offshore

, Louisian a

Gentlemen :

.

I n accordanc e wit h th e provision s o f Titl e 3 0 CF R 25 0 Subpar t B

, 55 0 Subpar t B an d furthe r define d i n

Notic e t o Lessee s (NTL ) 2010-N06

, 2009-G2 7 an d 2008-G04

, BH P Billito n Petroleu m (GOM ) Inc

. (herei n

referre d t o a s 'BHPB' ) hereb y submit s fo r you r revie w an d approva l a Supplementa l DOC D fo r th e abov e

reference d Unit

.

Enclose d ar e tw o (2 ) har d copie s (On e fo r Publi c Informatio n an d On e fo r Proprietar y Data ) wit h on e (1 )

C D fo r each

. Th e Stat e o f Louisian a CZ M doe s no t requir e a revie w a t thi s time

.

Unde r thi s Supplementa l DOC D BHP B propose s t o supplemen t th e Initia l DOC D Pla n No

. N-854 2 b y

drillin g on e (1 ) additiona l well

, installin g on e (1 ) associate d jumper

, flowline

, umbilica l an d commencin g productio n i n th e Atwate r Valle y Area

, Bloc k 574

, Leas e OCS- G 08035

, Offshore

, Louisiana

.

BHP B anticipate s commencin g drillin g operation s o n Augus t 1

, 2013

.

Shoul d additiona l informatio n b e required

, pleas e contac t th e undersigne d a t 713.599.6349

. Pleas e

forwar d al l approva l document s t o susan.wilson@bhpbilliton.com

.

Sincerely

,

Susa n Wilso n
Senio r Regulator y Specialis t

SW:K C

Enclosure s

## TABLE OF CONTENTS

SECTION 1:

CONTENTS OF PLAN

............................................................................................................................... . 1

Plan Information Form

............................................................................................................................... . 2

Bathymetry Map and Location Plat

............................................................................................................. 2

Safety and Pollution Prevention Features

................................................................................................... 2

Storage Tanks and Production Vessels

........................................................................................................ 3

Service Fees

................................................................................................................................................ 4

Pollution Prevention Measures to Prevent Discharge of Oils and Greases during Rainfall and Routine

Operations

................................................................................................................................................... 4

Safety, Pollution Preventio n and Early Spill Detection Measures

............................................................... 4



## SECTION 2:

GENERAL INFORMATION

......................................................................................................................... 5

Applications and Permits

............................................................................................................................. 5

Drilling Fluids

............................................................................................................................................... 5

Peak Production Rates / Life of Reserves

.................................................................................................... 5

Oil Characteristics

........................................................................................................................................ 5

New or Unusual Technology

....................................................................................................................... 5

Bonding Information

................................................................................................................................... 5

Oil Spill Financial Responsibility (OSFR)

....................................................................................................... 6

Deepwater Well Control Statement

........................................................................................................... 6

Suspensions of Production

.......................................................................................................................... 6

Blowout Sce nario

........................................................................................................................................ 6

Chemical Products

...................................................................................................................................... 8



## SECTION 3:

GEOLOGICAL AND GEOPHYSICAL INFORMATION

..................................................................................... 9

Geological Description

............................................................................................................................... . 9

Structure Contour Maps

........................................................................................................................... 10

Interpreted 2

‐ D or 3

‐ D Seismic Lines

........................................................................................................ 10

Geological Structure Cross

‐ Sections

......................................................................................................... 10

Shallow Hazards Report

............................................................................................................................ 10

Site Specific Shallow Hazards Assessment

............................................................................................... 10

High Resolution Seismic Lines

.................................................................................................................. 10

### Stratigraphic Column

............................................................................................................................... . 10

Time Versus Depth Table

.......................................................................................................................... 10

Geochemical Information

......................................................................................................................... 10

Future G&G Activities

............................................................................................................................... 10



## SECTION 4:

HYDROGEN SULFIDE INFORMATION

..................................................................................................... 11

Concentration

........................................................................................................................................... 11

Classification Request

............................................................................................................................... 11

Contingency Plan

...................................................................................................................................... 11

Modeling Report

....................................................................................................................................... 11



## SECTION 5:

MINERAL AND RESOURCE CONVERSATION INFORMATION

................................................................... 12

Technology and Reservoir Engineering Practices and Procedures

.......................................................... 12

Technology and Recovery Practices and Procedures

............................................................................... 12

Reservoir Development

............................................................................................................................ 12



## SECTION 6:

BIOLOGICAL, PHYSICAL AND SOCIOECONOMIC INFORMATION

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

Chemosynthetic Communities Report

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

Topographic Features Map

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

Topographic Features Statement

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

Live Bottom (Pinnacle Trend) Map

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

Live Bottom (Low Relief) Map

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

Potentially Sensitive Biological Features

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

ROV Monitoring Survey Plan

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

Threatened and Endangered Sp ecies Information

................................................................................... 14

Archaeological Report

.............................................................................................................................. 15

Air and Water Quality Information

.......................................................................................................... 15

Socioeconomic Information

..................................................................................................................... 15



## SECTION 7:

WASTE AND DISCHARGE INFORMATION

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

Projected Generated Wastes

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

Projected Ocean Discharges

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

Modeling Report

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

NPDES Permits

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

### Cooling Water Intakes

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



## SECTION 8:

AIR EMISSIONS INFORMATION

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

Screening Checklist

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

Summary Table(s) of Plan Emissions

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



## SECTION 9:

OIL SPILL INFORMATION

....................................................................................................................... 18

Site Specific OSRP

...................................................................................................................................... 18

Regional or Sub

‐ Regional OSRP Information

............................................................................................. 18

Spill Response Sites

................................................................................................................................... 18

OSRO Information

..................................................................................................................................... 18

Worst Case Scenario Determination

......................................................................................................... 19

NTL 2010

‐ NO6 ‐ WCD Calculations Overview

............................................................................................ 19

Oil Spill Response Discussion / NEPA Analysis

.......................................................................................... 20

Modeling Re port

........................................................................................................................................ 20



## SECTION 10:

ENVIRONMENTAL MONITORING INFORMATION

.................................................................................. 21

Monitoring Systems

.................................................................................................................................. 21

Incidental Takes

......................................................................................................................................... 21

Flower Garden Banks National Marine Sanctuary

................................................................................... 21



## SECTION 11:

LEASE STIPULATIONS INFORMATION

.................................................................................................... 22



## SECTION 12:

ENVIRONMENTAL MITIGATION MEASURES INFORMATION

.................................................................. 23

Impacts to Marine & Coastal Environments & Habitats, Biota, and Threatened & Endangered Species 23

Incidental Takes

......................................................................................................................................... 23



## SECTION 13:

DECOMMISSIONING INFORMATION

..................................................................................................... 24



## SECTION 14:

RELATED FACILITIES AND OPERATIONS INFORMATION

......................................................................... 25

Related OCS Facilities and Operations

..................................................................................................... 25

Transportation System

............................................................................................................................. 25

Produced Liquid Hydrocarbons Transportation Vessels

.......................................................................... 26



## SECTION 15:

SUPPORT VESSELS AND AIRCRAFT INFORMATION

................................................................................ 26

### General

...................................................................................................................................................... 26

Diesel Oil Supply Vessels

.......................................................................................................................... 26

Drilling Fluids Transportation

................................................................................................................... 26

Solid and Liquid Wastes Transportation.................................................................................................... 26

Vicinity Map

.............................................................................................................................................. 26



## SECTION 16:

ONSHORE SUPPORT FACILITIES INFORMATION

..................................................................................... 27

General

..................................................................................................................................................... 27

Support Base Construction or Expansion

.................................................................................................. 27

Support Base Construction or Expansion Timetable

................................................................................ 27

Air Emissions

............................................................................................................................................. 27

Unusual Solid and Liquid Wastes

.............................................................................................................. 27

Waste Disposal

......................................................................................................................................... 27



## SECTION 17:

SULPHUR OPERATIONS INFORMATION

................................................................................................. 28



## SECTION 18:

COASTAL ZONE MANAGEMENT ACT (CZMA) INFORMATION

................................................................. 29

Consistency Certification

.......................................................................................................................... 29

Other Information

..................................................................................................................................... 29



## SECTION 19:

ENVIRONMENTAL IMPACT ANALYSIS (EIA)

........................................................................................... 30

Impact Producing Factors (IPFs) from the Proposed Activities

................................................................ 30

Analysis

..................................................................................................................................................... 31

Environmental Hazards

............................................................................................................................ 39

Alternatives

............................................................................................................................................... 39

Mitigation Measures

............................................................................................................................... . 39

Consultation

............................................................................................................................................. 39

Preparer(s)

................................................................................................................................................ 39

References

................................................................................................................................................ 39



## SECTION 20:

ADMINISTRATIVE INFORMATION

......................................................................................................... 41

Exempted Information Description (Public Information Copies Only)

..................................................... 41

Bibliography

.............................................................................................................................................. 41

### Plan Attachments

Attachment A Plan Information Forms Attachment B Well Location Maps Attachment C Bathymetry Map Attachment D Pay.gov Service Fee

Attachment E PROPRIETARY DATA

Attachment F PROPRIETARY DATA

Attachment G PROPRIETARY DATA

Attachment H Shallow Hazards

Attachment I PROPRIETARY DATA Attachment J Solid and Liquid Wastes Transportation

Attachment K Air Emissions Attachment L NEPA Spill Response Discussion Attachment M Subsea Tree Drawing Attachment N Vicinity Map Attachment O Worst Case DischargeBHP Billiton Petroleum (GOM) Inc. 1 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### Supplemental Unit Development Operations Coordination Document (DOCD)

For Atwater Valley 574 Unit Agreement No. 754395004 Blocks 573, 574 , 575, 617 and 618

Leases OCS- G 08034, 08035 , 08036, 08037 and 08038

Offshore Louisiana



### SECTION 1 - CONTENTS OF PLAN

Under this Supplemental DOCD BHP Billiton Petroleum (GOM) Inc. (herein referred to as BHPB) is submitting the following information as a Supplement to the Initial DOCD (Control No. N-08542) granted to BHPB on May 3, 2006 to install a TLP (Platform A) and the infrastructure to produce thirteen (13) subsea wells. Initial production scenario consisted of seven (7) pre-drilled subsea wells (drilled in Atwater Valley Blocks 573, 574, 575, 617 and 618) connected to a daisy-chained, dual flowline system tied back to a tension leg platform (TLP) located in Green Canyon 613. The Initial DOCD granted approval to produce subsea wells SA001, SB001, SC001, SC002, SC003, SD001 and SD002. All subsea wells were both drilled and completed under an Initial or Suppl emental Exploration Plan or were proposed to be drilled and completed under the referenced plans.

BHPB proposes to supplement the DOCD as follows:

 Drill and complete Subsea Well 003 - located at a new proposed surface in Block 574

 Install a sled with one (1) jumper, one (1) 6.625 in ch flowline and associated 4 inch umbilical from the proposed SS003 well to one of two existing inline sleds (currently designated E and F)

 Commence production by January 1, 2014

The following is a history of the wells approved under Initial and Supplemental Plans:

Initial DOCD – Plan N-8542 – approved May 3, 2006

Well Name Complete Date Production Start

Date Status

TLP “A”

SA001 See Remarks TA’d 4/20/2007

SB001ST01 02/19/2008 07/21/2008

SC001ST03 11/30/2007 07/10/2008

SC002 07/04/2007 07/07/2008

SC003 08/15/2007 07/08/2008

SD001 10/10/2007 08/10/2008

SD001ST01 See Remarks Not drilled yet

SD002 See Remarks Not drilled yet

Revised DOCD

– Plan R-4376

– approved November 30, 2006 to revise air emissions for lease term pipelines.

Supplemental DOCD – Plan S-7198 – approved June 3, 2008

Well Name Complete Date Production Start

Date Status

SC004 05/10/2008 07/17/2008

Supplemental DOCD – Plan S-7343 – approved August 29, 2009

Well Name Complete Date Production Start

Date Status

SB002 09/16/2009 12/21/2009BHP Billiton Petroleum (GOM) Inc. 2 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 Supplemental DOCD – Plan S-7463 – approved September 11, 2011

Well Name Complete Date Production Start

Date Status

E001 Not Drilled Yet

E002 Not Drilled Yet

F001 Not Drilled Yet

F002 Not Drilled Yet

SA01ST01 P&A’d



### (a) Plan Information Form

An OCS Plan Information Form (BOEM-137) with details of the proposed drilling and completion operations and jumper and associated umbilical inst allation along with BHPB’s tentative schedule leading up to commencement of water injection is included as Attachment A

.

The proposed wells will be drilled with either a DP drill ship (CRL) or a DP semi-submersible (DD1) using

subsurface BOPs . There will be no anchors associated with the operations proposed in this Plan.



### (b) Bathymetry Map and Location Plat

The Well Location Plats along with a Bathymetry Map are included as Attachments B and C

, respectively. The location plats illustrate the existi ng and proposed surface and bottomhole locations of

the wells addressed in this Plan.

BHP Billiton proposes to utilize dynamically-positioned drilling vessels; therefore, t here will be no anchors associated with this activity.



### (c) Safety and Pollution Prevention Features

The proposed wells addr essed in this Plan will be drilled with the either a DP drillship or a DP semisubmersible using subsurface BOPs

.

Safety features on the MODU will include well contro l, pollution prevention, welding procedure, and blowout prevention equipment as descr ibed in the following Federal Register Notices, Notice to Lessees (NTL) and Subparts located in Title 30 CFR Part 250:

 Federal Register, Vol. 77, No. 163, August 22, 2012, Final Rule for Increased Safety Measures for Energy Development on the Outer Continental Shelf

 Federal Register, Vol. 75, No. 198, October 14, 2010, Final Rule for Increased Safety Measures for Energy Development on the Outer Continental Shelf

 NTL 2010-N06 for Information Requirements for Exploration Plans, Development and Production Plans, and Development Operations Coordination Documents on the OCS

 NTL 2010-N10 for Statement of Compliance wi th Applicable Regulations and Evaluation of Information Demonstrating Adequate Spill Response and Well Containment Resources

 Subpart C for Pollution Prevention and Control

 Subpart D for Oil and Gas Drilling Operations

 Subpart E for Oil and Gas Well-Completion Operations

 Subpart J for Pipelines and Pipeline Right-of-Ways

 Subpart K for Oil and Gas Production Requirements

 Subpart M for Unitization

 Subpart O for Well Control and Production Safety Training Subpart

 Subpart S for Safety and Environm ental Management Systems (SEMS)BHP Billiton Petroleum (GOM) Inc. 3 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 These regulations may be further clarified by Safe ty Alerts, and current policy making invoked by the Bureau of Ocean Energy Management, Regulation a nd Enforcement (BOEM), Environmental Protection Agency (EPA) and the U.S. Coast Guard (USCG).

The appropriate life rafts, life jackets, ring buoys, et c., as prescribed by the U.S. Coast Guard will be

maintained on the MODU at all times.

BSEE is required to conduct onsite inspections of offshore facilities to confirm operators are complying with lease stipulations, operating regulations, approved plans, and other conditions; as well as to assure safety and pollution prevention requirements are being met. The National Potential Incident of Noncompliance (PINC) List serves as the baseline for these inspections.

BSEE also inspects the stockpiles of equipment listed in the Operator's approved Subregional Oil Spill Response Plan that would be used for the containment and cleanup of hydrocarbon spills and is further addressed in the “Oil Spill Information” section of this Plan.

In accordance with Title 30 CFR 250.1501, the goal of our training program is safe and clean OCS operations. To accomplish this, BHPB ensures that our employees and contractor personnel engaged in well control understand and can properly perform their duties.

Supervisory and certain designated personnel on-board the facility are to be familiar with the effluent limitations and guidelines for over board discharges into the receivi ng waters, as outlined in the EPA’s NPDES General Permit GMG290000. Some of these pol lution prevention measures include installation of curbs, gutters, drip pans, and drains on drilling deck areas to collect all contaminants and debris.

All discharges related to the oper ations proposed in this Plan ar e covered under EPA’s NPDES General Permit referenced above. BHPB’s permit number is GMG290184.



### (d) Storage Tanks and Production Vessels

Tanks with a capacity of 25 bbls or more of oil as defined at 30 CFR 254.6 is listed below:

Type of Storage

Tank Type of Facility Tank Capacity (bbls) Number of

Tanks Total Capacity (bbls) Fluid Gravity (API)

Lube Oil Tank P / S Drillship – CRL 661 2 1322 29-39 o

Dirty Oil Tank AFT Drillship – CRL 296 1 296 29-39 o

Dirty Oil Tank FWD Drillship – CRL 69 1 69 29-39 o

Diesel Oil Drillship – CRL 8549(2); 7906(2); 3736(2); 2665(2); 290(2); 775(4) 12 49,392 29-39 o

Base Oil Drillship – CRL 3541 1 3541 29-39 o

Type of Storage

Tank Type of Facility Tank Capacity (bbls) Number of

Tanks Total Capacity (bbls) Fluid Gravity (API) Fuel Tanks (005, 006, 007, 008) DP Semisubmersible DD-1 77178 4 308,712 29-39 o

Fuel Tank (009) DP Semisubmersible DD-1 3003 1 3,003 29-39 o

Fuel Tank (010) DP Semisubmersible DD-1 2585 1 2,585 29-39 o

Fuel Tank (011) DP Semisubmersible DD-1 5228 1 5,228 29-39 o

Base Oil DP Semisubmersible DD-1 3541 1 3541 29-39 oBHP Billiton Petroleum (GOM) Inc. 4 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### (e) Service Fees

In accordance with 30 CFR 250.125 (a) BHPB has used the following table showing the fees that must be paid to BOEM for the activity proposed in this Plan. The fees will be adjusted periodically according to the Implicit Price Deflat or for Gross Domestic Product by public ation of a document in the Federal Register. If a significant adjustment is needed to arri ve at the new actual cost for any reason other than inflation, then a proposed rule containing the new fees will be published in the Federal Register for

comment.

Service Fee Table

Service — processing of the following: Fee amount 30 CFR citation

Supplemental Development Operations Coordination Document (DOCD) $4,238 per well §250.211

[70 FR 49875, Aug. 25, 2005, as amended at 71 FR 40909, July 19, 2006; 72 FR 25199, May 4, 2007; 73 FR 49946, Aug. 25, 2008; 75 FR 20288, Apr. 19, 2010]

A copy of the receipt for payment of the above referenced fee(s) ac companies the submission of this

document as Attachment D . It is our understanding that once a fee is paid, it is nonrefundable, even if an application or other request is withdrawn. If our application is returned as incomplete, we are not required to submit a new fee if and when we submit an amended application.



### (f) Pollution Prevention Measures to Prevent the Discharge of Oils and Greases during Rainfall and Routine Operations

Supervisory and certain designated personnel on-board the MODU and / or the facility are to be familiar with the effluent limitations and guidelines for overb oard discharges into the receiving waters, as outlined

in EPA’s NPDES General Permit GMG290000.

Some of these pollution prevention me asures include installation of curbs, gutters, drip pans, and drains to collect all contaminants and debris to prevent the di scharge of oils and greases from drilling rigs or platforms during rainfall and routine operations.

BHPB will utilize the best management practices availabl e for ensuring all operations are performed in a

safe and workmanlike conduct in accordance with 30 CFR 250.107 and will ensure that our employees and contractor personnel engaged in our offshore dr illing operations underst and the state and federal regulations.

All discharges related to the oper ations proposed in this Plan ar e covered under EPA’s NPDES General Permit referenced above. BHPB’s permit number is GMG290184.



### (g) Safety, Pollution Prevention, and Early Spill Detection Measures

In accordance with the provisions of Title 30 CF R Parts 254.2(b), 254.23, 254. 24, 254.25 and 254.26(d) and as further defined by Notice to Lessees (NTL) 2010-N10, BHPB submitted for review and BOEM has accepted a proposed Containment Plan which outlines t he response to a complete loss of well control. BHPB is a signatory to the "Agreement for Response Resources" between Clea n Gulf Associates and Helix Energy Solutions Group Inc, for the "H elix Fast Response System (HFRS)".

At this time, use of the HFRS is at the core of the Containment Plan, however, BHPB also fully intends participating in the Marine Well Containment Corp. (M WCC) venture for oil-spill containment equipment. MWCC will have interim capabilities to augment our Containment Plan in the near term and full capabilities to augment our Plan in the future.

These are also addressed above in Sections (c) and (f)

.BHP Billiton Petroleum (GOM) Inc. 5 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 2 - GENERAL INFORMATION

(a) Applications and Permits

Application / Permit Issuing Agency Status

APD’s BSEE District To be submitted via eWell

Supplemental DWOP BSEE Region In preparation

Lease Term Pipelines BSEE Region In preparation

Surface Safety Systems BSEE District In preparation

Notice of Intent to Discharge EPA Region 6 In preparation



### (b) Drilling Fluids

(1) The following table provides information on the types and amounts of the drilling fluids BHPB plan to use during drilling operations.

Type of Drilling Fluid Estimated Volume of Drilli ng Fluid to be Used

Water-based (SW, FW, Barite) 16,035 bbls

Oil-based (diesel, mineral oil) NA
Synthetic-based (internal olef in, ester, etc) 1,703 bbls



### (i) Since BHPB does NOT intend to use oil-based drilling fluid (as shown above) then the table of major components is not required at this time.

(ii) Material Safety Data Sheets (MSDS) are not required at this time.



### (c) Peak Production Rates / Life of Reserves

PROPRIETARY DATA



### (d) Oil Characteristics

There is no change to the information previously subm itted with the Initial DOCD (Control No. N-08542).



### (e) New or Unusual Technology

BHPB does not propose the use of any new or unusual technology in the development activities proposed under this plan.



### (f) Bonding Information

The bond requirements for the activities and facilities pr oposed in this Supplemental Plan are satisfied by an area-wide bond furnished and maintained according to 30 CFR Part 256, Subpart I; NTL No. 2000- G16, “Guidelines for General Lease Surety B onds”; and National NTL No. 2008-N07, “Supplemental

Bond Procedures”.BHP Billiton Petroleum (GOM) Inc. 6 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### (g) Oil Spill Financial Responsibility (OSFR)

BHPB (BOEM Operator No. 02010) has demonstrated o il spill financial responsibility for the facilities proposed in this Supplemental Plan 30 CFR Part 253, an d NTL No. 2008-N05, “G uidelines for Oil Spill Financial Responsibility for Covered Facilities”.



### (h) Deepwater Well Control Statement

BHPB (BOEM Operator No. 02010) has the financial capability to drill a relief well and conduct other emergency well control operations.



### (i) Suspensions of Production

At this time there are no approved or anticipated suspensions of production needed to hold the leases or

unit involved with our DOCD.



### (j) Blowout Scenario

The proposed wells will penetrate the objective, hydrocarbon bearing sands with a 12-1/4-inch drilling assembly below the 13-5/8-inch intermediate casing stri ng. It is assumed that a hydrocarbon influx is taken while tripping out of the hole, and subsequently an uncontrolled well control event occurs in which the BOPs fail to function as designed and subsequently the marine riser fails. The end result is an

uncontrolled blowout at the sea floor.

The expected spill rate for this scenario would be 101,730 STB/Day of 22.9o API gravity oil (initial oil rate). It is assumed that the well will not bridge over and will continue to flow until the well is either capped by subsea containment devices or is killed via a relief well. Due to the complex nature of the flux calculation and mechanical earth modeling, BHPB considers that it is not possible to predict with certainty if the open hole section will collapse and bridge off. BHPB has two (2 ) rigs contracted and working in the Gulf of Mexico that are capable of drilling in 7,500ft of water if a relief well is required. It is estimated that it would

take 10 days to acquire a rig and move onto location with approximately 90 days to drill the relief well and perform kill operations, for a total of 100 days.

Based on 100 days, the estimated cumulative discharge volume is 10.173 MMSTB oil.



### Relief Rig Availability

BHPB has two 5 th generation rigs on contract capable of drilling in at least 7,500ft of water. Both rigs are planned to continue to operate in the Gulf of Mexico.



### Relief Rig Package Constraints No constraints have been identified preventing either rig from drilling a relief well. Both MODU’s are rigged up for fracturing / high rate pumping operations . There are several stimulation vessels in the GOM which could also be used for kill operations.



### Relief Rig Timing (Contract) and Rig Mobilization BHPB has two rigs on contract operating in the Gulf of Mexico. A reasonable assumption would be that it would take 7 – 10 days for the relief well rig to safely suspend operations on the current well and move to the relief well location. Upon arrival at location, it would be expected to take approximately 90 days to

drill the relief well and perform kill operations.



### Location & Strategy of Relief Well As the Neptune wells are located approximately 114 statute miles off the coast of Louisiana, a relief well from an onshore location is not an option.

There are no structures in the vicinity of this project to us e for relief well drilling operations.BHP Billiton Petroleum (GOM) Inc. 7 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### Summary of Prevention Measures BHPB maintains and adheres to an ISO 14001 / OSHAS 18001 Conformance Certified Management System which includes Well Control, Well Integrity [including barrier analyses], and Well Design Standards which have been updated to include the initial learning’s from the Deepwater Horizon incident. BHPB have established procedures for performing drilling operations that are continually updated and designed to be “fit for purpose” to ensure each we ll is planned to prevent a well control scenario:

 BHPB employs an industry leading expert to prov ide initial pore pressure and fracture gradient predictions. Having this expertise and knowledge in-house allows for the successful planning of a

well to minimize the chances of a blowout.

 Well hazard assessments are performed on every well focusing particularly on well integrity, well control and emergency response arrangements.

 A well risk assessment is conducted as part of the well planning process, and a risk register is completed and documented in the drilling program addressing each of the risks.

 If while drilling a well, situations change such that t he original drilling program requires to be amended, a Management of Change is issued, and if necessary, a barrier a nalysis is conducted. The Management of Change form is signed off by management and issued to operations personnel for implementation.

 BHPB Senior Leadership personnel are actively engaged in daily rig operations.

 BHPB employs experienced and trained Field Operations Personnel.

 BHPB conducts periodic we ll control audits of ou r contracted drilling rigs by both BHPB drilling management and independent third party (well examiner) auditors.



### Reduce the Likelihood of a Blowout Real time pressure and well data is monitored from the BHPB Houston office during drilling operations. This includes utilizing Gamma Ray an d Resistivity LWD and in certain cases form ation pressure while drilling tools.

The following BHPB policies directly reduce the likelihood of a blowout:

 Liners will be run across hy drocarbon beari ng formations.

 No auto-fill float equipment will be ru n when hydrocarbon zones are exposed.

 No surface fluid transfers to occur while displacing to a less dense fluid.

 All displacements to less dense fluids will be pe rformed on a closed system where fluid volumes can be closely and accurately monitored.

A well control drill matrix is maintained on the rig as per 30 CFR Subpart O.

The BOP stacks on the C.R. Luigs and Development Dr iller-1 rigs are both six (6) ram stacks configured to provide enhanced well control and emergency response capability, including dual blind shear rams, casing shear rams, and three variable bore pipe rams. These configurations have been in place since the rigs first began work with BHPB (since 2000 for the CRL and 2005 for the DD1). As such, procedures pertinent to these BOP configurations are well establ ished and familiar to the drillers, tool pushers, and BHPB Drilling Supervisors.



### Likelihood for Surface Intervention to Stop the Blowout

The likelihood for surface intervent ion to stop the blowout is high.

The 13-5/8” intermediate long string will design for a full column of oil to the mudline. As a result, it would be possible to install a containment device (such as a capping stack) which would subsequently allow for the blowout to be stopped.

BHPB has standardized the BOP wellhead connector for both of its contracted MODU’s, the Development Driller I and the C.R. Luigs, to ensure that either rig is capable of latching onto an existing BHPB

wellhead.BHP Billiton Petroleum (GOM) Inc. 8 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### Plans for Effective and Early Intervention Both rigs contracted by BHPB have a Deadman / Autoshear which will fu nction in the event of a LMRP disconnect or a loss of both hydraulic pressure and electrical communication with the BOP control system

on surface.

“Surface” deployment of ROVs to close any open BOPs which could affect well closure:

 The ROV panel will be tested subsea with the BOP on a wellhead.

 BHPB has upgraded the pump skid on the rigs’ ROV’s with a more powerful pump capable of producing higher flow rates. Additionally, the receptacles have been changed to allow for more flow rate to reduce closing times.

 BHPB has designed, built, tested and deployed dedicated subsea accumulator banks to the seafloor to further improve the ROV closure response times.

BHPB is a member of the Marine Well Containment Company (MWCC) group, which maintains capping and well control equipment for its member companies.



### Relief Well Arrangements

Suitable surface locations for a relief well would fall within the stand-off zone defined by a 5000’ radius

with its center at the AT 574 SS003 surface location. Shallow hazards analysis indicates favorable relief well locations within this area provided that existing infr astructure, localized areas of steep seafloor slope, and scattered gas anomalies are avoided (see SH screening map in Attachment H).

The well design should reflect the original well, depending on the root cause of the blowout.

Key Rig Specifications for Relief Well

Rig Name DD1 C.R. Luigs

Rig type 5th Gen MODU rated for 7,500 ft water
depth, Dynamically Positioned 5th Gen MODU rated for 10,000 ft
water depth, Dynamically Positioned

BOP size & pressure rating 18.75 - 15,000 psi 18.75 - 15,000 psi

Max Hookload (kips) 2,000 kips 1,800 kips

Drawworks power (hp) 6,900 hp 5,000 hp

Mud pumps Power & Pressure (hp/psi) 4 x 14-P-220 NOV pumps with 2,200
7,475 psi working 4 x 14-P-220 NOV pumps with 2,200
7,475 psi working

Mud pit volume (bbls) 19,298 bbls (VDL limited) 13,267 bbls

Variable Loading (kips) 15,432 kips Drilling N/A Drill Ship
Top Drive Power & Torque (hp/ftlbs) Hydralift HPS 1000 2E (AC) NOV TDS-4

Dry bulk storage capacity (cu.ft) 16,950 cu/ft Cement & 10,416 cu/ft
Barite (VDL Limited) Total Bulk 27,000 cuft



### Other Measures Taken Prior to drilling in AT574, BHBP will have readily available all of the materials and equipment needed to spud, drill, case and cement a relief well.

BHPB has established commercial relationships with those suppliers of contingency equipment and

services that we have identified as necessary to kill a blown out well.



### (k) Chemical Products

This information is not required for the activities proposed in this plan in the BOEM GOMR.BHP Billiton Petroleum (GOM) Inc. 9 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 3 - GEOLOGICAL AND GEOPHYSICAL INFORMATION

In accordance with 43 CFR 2.13 (c) (9), those items considered proprietary have been omitted from the Public Information copy and have been referenced accordingly.



### (a) Geological Description

PROPRIETARY DATA



### (b) Structure Contour Maps

Enclosed as Attachment E are current structure maps drawn to the top of the proposed water injection zone(s). The surface and bottom hole location(s) along with the locations of the geologic cross-sections of the well(s) to be injected into under this Supplemental DOCD are included.BHP Billiton Petroleum (GOM) Inc. 10 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### (c) Interpreted 2-D or 3-D Seismic Lines

PROPRIETARY DATA



### (d) Geological Structure Cross-Sections

PROPRIETARY DATA



### (e) Shallow Hazards Report

A Site Specific Shallow Drilling Hazards Report fo r the SS003 location in Atwater Valley Block 574, Lease OCS-G 08035 was prepared by Shawn C. Williamson, P.G. Geohazar ds Interpreter for BHPB on April 16, 2013. The report is based on several previous report s submitted during the exploratory phase of the Neptune Project.

A copy of this site specific report is included in Attachment H

.



### (f) Site Specific Shallow Hazards Assessment

A Site Specific Shallow Drilling Hazards Assessment for SS003 located in Atwater Valley Block 574, Lease OCS-G 08035 was prepared by Shawn C. Willia mson, P.G. Geohazards Interpreter for BHPB on April 16, 2013.

This assessment is included in Attachment H

.



### (g) High Resolution Seismic Lines

3-D Seismic Data. The 3D seismic data used are from the Western Geophysical Ultra Survey Atwater Phase 5. The full-fold migrated 3-D volume contains 4-msec sample rate data at a bin spacing of 41.0 x 65.6 ft (12.5 m x 20 m). The data were enhanced with s pectral whitening and coherency filtering and have an overall bandwidth of 7–75 Hz. The data are relative amplitude processed for hydrocarbon detection. Locally, 3D seismic amplitude response is attenuated at depth in proximity to the seaward limit of the Sigsbee Salt. Pre-stack depth migrated data based on this survey have also been used to help understand the structural setting for the Neptune Field. More information on this survey can be accessed at: http://www.multiclient.westerngeco .com/NavPDFs/ultra_surveys11.pdf.



### (h) Stratigraphic Column

PROPRIETARY DATA



### (i) Time Versus Depth Tables

This information is not required for DOCD’s.



### (j) Geochemical Information

This information is not required for the activities proposed in this plan in the BOEM GOMR.



### (k) Future G&G Activities

This information is not required for the activities proposed in this plan in the BOEM GOMR.BHP Billiton Petroleum (GOM) Inc. 11 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 4 - HYDROGEN SULFIDE INFORMATION

(a) Concentration

BHPB does not anticipate encountering H 2 S while conducting our proposed development activities.



### (b) Classification Request

In accordance with Title 30 CFR 250.490(c), BHPB requ ests the area of operations in Atwater Block 574, Lease OCS-G 08035, be classified by the BOEM as an area where the “absen ce” of Hydrogen sulfide has been confirmed based upon the following:

PROPRIETARY DATA



### (c) Contingency Plan

BHPB does not anticipate encountering H 2 S while conducting our proposed development activities therefore a contingency plan is not required at this time.



### (d) Modeling Report

BHPB does not anticipate encountering H 2 S while conducting our proposed development activities therefore a modeling report is not required at this time.BHP Billiton Petroleum (GOM) Inc. 12 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 5 - MINERAL AND RESOURCE CONVERSATION INFORMATION

(a) Technology and Reservoir Engineering Practices and Procedures

PROPRIETARY DATA



### (b) Technology and Recovery Practices and Procedures

PROPRIETARY DATA



### (c) Reservoir Development

PROPRIETARY DATABHP Billiton Petroleum (GOM) Inc. 13 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 6 - BIOLOGICAL, PHYSICAL AND SOCIOECONOMIC INFORMATION

(a) Chemosynthetic Communities Report

NTL 2009-G40, effective January 27, 2009, broad ened the scope of a chemosynthetic communities report to cover all high-density deepwater benthic co mmunities (not just high-density chemosynthetic communities), changed the definition of deepwater from 400 meters (1,312 feet) to 300 meters (984 feet), increased the separation distance from muds and cu ttings discharge locations from 1,500 feet to 2,000 feet and provided for an additional 1,000-foot buffer area beyond maximum anchor areas.

Seafloor and shallow subsurface conditions are favor able for drilling operations at Atwater Valley SS003

location. No man-made obstructions were identified from the AUV data in the immediate vicinity of the proposed location. There are no hydrocarbon macro-s eeps or hard bottom areas capable of supporting high-density benthic communities within 2,000ft of t he proposed location. Appropriate drilling precautions should be taken to mitigate shallow water flow risk as sociated with interpreted sandy intervals. There are no indications of free-phase gas in the s uprasalt section at the proposed location.



### (b) Topographic Features Map

There are no topographic features located on Atwater Valley 574.



### (c) Topographic Features Statement

Since there are no topographic features locate d on Atwater Valley 574 the statement for shunting described in NTL No. 2009-G39 “Biologically Sensitive Underwater Features and Areas” is not required.



### (d) Live Bottom (Pinnacle Trend) Map

The activities proposed in this plan are not affect ed by a live bottom (Pinnacle Trend) stipulation attached

to the lease.



### (e) Live Bottom (Low Relief) Map

The activities proposed in this plan are not affected by a live bottom (low relief) stipulation attached to the

lease.



### (f) Potentially Sensitive Biological Features

BHPB does not propose bottom-disturbing activities wi thin 61 meters (200 feet) of potentially sensitive biological features; therefore the map described in NTL No. 2009-G39 “Biologica lly Sensitive Underwater Features and Areas” is not required.



### (g) ROV Monitoring Survey Plan

BHPB is familiar with the ROV survey and reporting provisions of NTL 2008-G06 for “Remotely Operated Vehicles in Deepwater”. The wells proposed in this Supplemental Plan are located in Grid 13. Grid 13 has been identified by BOEM as an area with adequate ROV survey coverage.BHP Billiton Petroleum (GOM) Inc. 14 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### (h) Threatened and Endangered Species Information

Congress passed the Endangered Species Act (ESA) on December 28, 1973, recognizing that the natural heritage of the United States was of “esthetic, ecologica l, educational, recreational, and scientific value to our Nation and its people.” It was understood that, without protection, many of our nation’s living

resources would become extinct. The purpose of the ESA is to co nserve threatene d and endangered species and their ecosystems. Ther e are more than 1,900 species li sted under the ESA. A species is considered endangered if it is in danger of extinction throughout all or a significant portion of its range. A species is considered threatened if it is likely to become endangered in the future. The U.S. Fish and Wildlife Service (USFWS) and the National Marine Fi sheries Service (NMFS) share responsibility for implementing the ESA. NMFS is responsible for 69 marine species, from whal es to sea turtles and salmon to Johnson’s sea grass.

The Marine Mammal Protection Act (MMPA) of 1972 was written to establish American federal responsibility to conserve marine mammals. Some species were in immediate danger of extinction while other populations were becoming severely depleted.

Below is a list of endangered and threated species and critical habitats under the jurisdiction of NOAA

Fisheries Service in the Gulf of Mexico:

Listed Species Scientific Name Status Date Listed

Marine Mammals

Blue Whale Balaenoptera Musculus Endangered 12/02/1970

Finback Whale Balaenoptera Phys alus Endangered 12/02/1970 Humpback Whale Megaptera Novaean gliae Endangered 12/02/1970

Sei Whale Balaenoptera Borealis Endangered 12/02/1970 Sperm Whale Physeter Macrocephalus Endangered 12/02/1970

Turtles Green Sea Turtle Chelonia Mydas Threatened 1 07/28/1978 Hawksbill Sea Turtle Eretmochelys Imbricata Endangered 06/02/1970 Kemp’s Ridley Sea

Turtle Lepidochelys Kempii Endangered 12/02/1970

Leatherback Sea Turtle Dermochelys Coriacea Endangered 06/02/1970 Loggerhead Sea Turtle Caretta Caretta Threatened 2 09/22/2011

Fish Gulf Sturgeon Acipenser Oxyrinchus Desotoi Threatened 09/30/1991

Smalltooth Sawfish Pristis Pe ctinata Endangered 04/01/2003

Invertebrates

Elkhorn Coral Acropora Palmata Threatened 05/09/2006 Staghorn Coral Acropora Cervic ornis Threatened 05/09/2006

1 Green turtles are listed as threatened, except for breeding populations of green turtles in Florida and on the Pacific Coast of Mexi co, which are listed as endangered.

2 Northwest Atlantic Ocean (NWA) Distinct Population Segment (D PS) was listed as threatened. NMFS and USFWS issued a final rule changing the listing of loggerhead sea turtles from a single, threaten ed species to nine DPSs listed as either threatened or endangered in 2012 (76 FR 58868).

BHPB is aware of the above referenced federal acts and will ensure that all offshore personnel, including contractors and other support services-related personnel have an understanding of the need to conserve marine mammals and the conservation of their ecosystems. Several NTL’s were issued to address conservation measures to be taken by o ffshore operators and contractors.

Further discussions on threatened and endangered species are included in Section 19 (EIA).BHP Billiton Petroleum (GOM) Inc. 15 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### (i) Archaeological Report

BHP Billiton Petroleum Inc., (BHPB) provided an ar chaeological assessment of previously collected Autonomous Underwater Vehicle (AUV) data to comp ly with the Bureau of Ocean Energy Management Regulation and Enforcement’s (BOEM) newly issu ed “Pre-Seabed Disturbanc e Survey Mitigation” guidelines to BOEM on February 27, 2013. The control number assigned by BOEM for this document is Survey No. 23658

.

This report is intended to provide details pertaining directly to the area of potential effect of BHPB’s proposed wells in at 574.



### (j) Air and Water Quality Information

The State of Florida is not an affected State for t he activities proposed in this plan; therefore this information is not required.



### (k) Socioeconomic Information

The State of Florida is not an affected State for t he activities proposed in this plan; therefore this information is not required.BHP Billiton Petroleum (GOM) Inc. 16 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 7 - WASTE AND DISCHARGE INFORMATION

(a) Projected Generated Wastes

All projected solid and liquid wastes likely to be generated by our proposed activities are included in Attachment J (Table 1) . This table includes both operational wastes permitted by the appropriate NPDES permit and any other identified wastes.

BHPB does not plan to treat, store or dispose of an y of the above wastes down hole at our proposed drilling location.



### (b) Projected Ocean Discharges

All projected solid and liquid wastes likely to be discharged overboard during our proposed activities are

included in Attachment J (Table 1) . This table includes both operat ional wastes permitted by the appropriate NPDES permit and any other identified wastes.



### (c) Modeling Report

Not required by EPA under the OCS General Permit.



### (d) NPDES Permits

This information is not required for the activities proposed in this plan in the BOEM GOMR.



### (e) Cooling Water Intakes

This information is not required for the activities proposed in this plan in the BOEM GOMR.BHP Billiton Petroleum (GOM) Inc. 17 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 8 - AIR EMISSIONS INFORMATION

(a) Screening Checklist

Included in this section, (if applicable) are the Projected Air Emissions Worksheets prepared in

accordance with NTLs 2009-G27 and 2008-G 04, associated with the Neptune Field.

Screening Questions for DOCD’s Yes No Is any calculated Complex Total (CT) Emission amount (in tons) associated with your proposed development

activities more than 90% of the amounts calcul ated using the following formulas: CT = 3400D 2/3 for CO, and CT = 33.3D for other air pollutants (where D = distance to shore in miles)? X

Do your emission calculations include any emission r eduction measures or modifi ed emission factors? X Does or will the facility complex associated with yo ur proposed development and pr oduction activities process production from eight or more wells? X

Do you expect to encounter H 2 S at concentrations greater than 20 parts per million (ppm)? X Do you propose to flare or vent natural gas in excess of the criteria set forth under 250.1105(a)(2) and (3) X Do you propose to burn produced hydrocarbon liquids? X
Are your proposed development and production activities located within 25 miles from shore? X
Are your proposed development and production activities located within 200 kilometers of the Breton

Wilderness Area? X

The following information was prepared by Kathy Camp, 713.201.9627, based upon drilling and completion information provided by BHP Billiton Petroleum Drilling group.



### (b) Summary Table of Plan Emissions

Below are the Total Plan Emissions for well SS003. The Neptune TLP and proposed Well is not

collocated activities.

The planned emissions are associated with drilling and completing of the wells with either the drillship C.R. Luigs or the DP semi-submersible DD 1 and installing flowline infrastructure.

COMPANY AREA BLOCK LEASE PLATFORM WELL

BHP Billiton Pet. (GOM) Inc. Atwater Valley 574 OCS-G 08035 NA SS003 (CRL)

Year Emitted Substance

PM SOx NOx VOC CO

2014 53.76 0.99 166 7.51 65.35 409.99

Allowable 3796.20 3796.20 3796. 20 3796.20 79937.18

COMPANY AREA BLOCK LEASE PLATFORM WELL

BHP Billiton Pet. (GOM) Inc. Atwater Valley 574 OCS-G 08035 NA SS003 (DD1)

Year Emitted Substance

PM SOx NOx VOC CO

2014 44.77 0.85 1558.04 56.28 376.36

Allowable 3796.20 3796.20 3796. 20 3796.20 79937.18

Detailed spreadsheets are included as Attachment K.BHP Billiton Petroleum (GOM) Inc. 18 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 9 - OIL SPILL INFORMATION

(a) Oil Spill Response Planning

(1) Site-Specific OSRP

Lease OCS-G 08035 is not located in the Easter n Gulf of Mexico therefore a site-specific OSRP is not required.

(2)(i) Regional or Sub-Regional OSRP Information

BHP Billiton Petroleum (GOM) Inc. (Company No. 02010) has an approved Regional OSRP (No. O-43).

The calculated WCD for Lease OCS-G 08035 does not supersede the Regional OSRP’s

WCD.

All the proposed activities and facilities in this Supplemental DOCD will be covered by the Oil Spill Response Plan filed by BHP Billit on Petroleum (GOM) Inc. (Company No. 02010) that was approved on November 21, 2013.

(ii) Spill Response Sites

The location of BHPB’s primary spill response equipment and the planned staging area(s) that would be used should we have an oil spill resulting from the activities proposed in our Supplemental Plan is provided in the table below:

Primary Response Equipment Location Preplanned Staging Location(s)

Port Fourchon or Houma, LA Port Fourchon, LA

(iii) OSRO Information

BHPB’s primary equipment provider is Clean Gulf Associates (CGA). Clean Gulf Associates Services, LLC (CGAS) will provi de closest available personnel, as well as a CGAS supervisor to operate the equipment.BHP Billiton Petroleum (GOM) Inc. 19 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 (iv) Worst Case Scenario Determination

The calculated WCD for this Supplemental DOCD on Lease OCS-G 08035 does not supersede the Regional OSRP’s WCD.

Category Regional OSRP Supplemental

DOCD Regional

OSRP Supplemental

DOCD Type of Activity >10 Miles Drilling >10 Miles
Drilling >10 Miles

Production >10 Miles

Production Facility Location (area/block) GC 610 AT 574 GC 653 AT 574 Facility Designation 2 Well SH103 ST01 Subsea Well

E001 TLP “A” SS003

Distance to Nearest Shoreline (miles) 120 114 120 114

Volume 3

Storage tanks (total) Flowlines (on facility) Lease term pipelines Uncontrolled blowout (volume per day)

Total Volume n/a
n/a
n/a

255,200 bbls

255,200 bbls* n/a
n/a
n/a

101,730 bbls

101,730 bbls** 4,098 bbls
n/a

8,474 bbls

111,084 bbls

123,656 bbls n/a
n/a

40 bbls

19,650 bbls

19,690 bbls Type of Oil(s) (crude oil, condensate, diesel) Crude Crude Crude Crude API Gravity(s) 4 32.1° 22.9o 30o 21.3o

*The Regional OSRP calculations and assumptions fo r blowout during drilling were previously submitted and accepted under Plan S-7487. ** The WCD for the Neptune Field was verified by BOEM and accepted via email to BHP on March 7,

2011 under Plan S-7463.

Footnotes: 1. Types of activities include pipeline, platform, caisson, subsea completion or manifold, and mobile drilling rig. 2. E.g., Well No. 2, Platform JA, Pipeline Segment No. 6373. 3. Take your regional OSRP worst-case scen ario volume from the appropriate section of your regional OSRP. For EP’s, the wors t-case scenario volume is the daily volume possible from an uncontrolled blowout. Determine this volume using the provisions of 30 CFR 30 CFR 2 54.47(b). For DOCD’s, determine the volume of your worst-case scenario using the provisions of 30 CFR 30 CFR 254.47(a) or (b), as appropr iate. 4. Provide API gravity of all oils given unde r “Type of Oil(s)” above. Estimate for EP’s.

Since BHPB has the capability to respond to the appropriate worst-case spill scenario included in its regional OSRP approved on November 21, 2013, and since the worst-case scenario determined for our Supplemental DOCD does not replace the appropriate worst-case scenario in our regional OSRP, I hereby certify that BHPB has the capability to r espond, to the maximum extent practicable, to a WCD, or a substantial threat of such a discharge, resulting from the activities proposed in our Supplemental DOCD.



### NTL 2010-N06 – WCD Calculations Overview

PROPRIETARY DATA

BOEM reviewed and calculated a WCD of 101,730 BOPD under Supplemental DOCD Plan No. S-7463 in March 2011. The WCD volume for SS003 is 29,130 STB oil/day and does not supersede the WCD in BHPB’s approved OSRP. The estimated cumulative disc harge volume after 30 days is 0.84 MMSTB oil. Table 1 shows the expected WCD rate s at t=1 day and over the time ta ken to drill a relief well (up to 100 days).

Since the WCD for the Neptune Field was verified by BOEM and accepted via email to BHP on March 7, 2011 under Plan S-7463, BHPB has only included the SS003 WCD for information purposes in

Attachment O

.BHP Billiton Petroleum (GOM) Inc. 20 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### (b) Oil Spill Response Discussion / NEPA Analysis

For the purpose of NEPA and Coastal Zone Management Act analysis, the largest spill volu me originating from the proposed activity would be a well blowout during drilling operations, estimated to be 101,730 barrels of crude oil with an API gravity of 22.9°.

BHPB’s detailed spill response discussion is included as Attachment L

.



### (c) Modeling Report

A modeling report for a potential oil or hazardous subs tance spill is not required for the activities proposed in this plan. In the event BHPB proposes to pr epare such a report, we would contact the Regional Supervisor of the BOEM GOMR for guidance in preparing the report and the BOEM GOMR would be provided with two copies.BHP Billiton Petroleum (GOM) Inc. 21 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 10 - ENVIRONMENTAL MONITORING INFORMATION

(a) Monitoring Systems

BHPB is aware of the requirements of NTL No. 2009-G02 whereby BOEM established and implemented a program to monitor ocea n currents and require operators to shar e the data for all floating MODU’s and production facilities operating or installed in wa ter depths greater than 400 meters (1,312 feet).

In the event BHPB were to monitor ocean currents durin g this operation, BHPB will report ocean current data to the National Oceanic and Atmospheric Administra tion (NOAA) National Data Buoy Center (NDBC) Internet website as required.



### (b) Incidental Takes

BHPB does not believe that protected species may be incidentally taken during the development activities proposed in this plan.



### (c) Flower Garden Banks National Marine Sanctuary

BHPB’s activity under this Plan is not located within the Protective Zones of the Flower Garden Banks or Stetson Bank and therefore is not required to monitor the impacts of an oil spill.BHP Billiton Petroleum (GOM) Inc. 22 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 11 - LEASE STIPULATIONS INFORMATION

Oil and gas exploration and development activities on the OCS are subject to stipulations developed before the lease sale and would be attached to the lease instrument, as necessary, in the form of mitigating measures. The MMS is responsible for ensuring full compliance with stipulations.

The MMS did not invoke lease stipulations fo r Lease OCS-G 08035, Atwater Valley Block 574.

Atwater Valley Block 574 is located within the boundaries of the Gulfmex No. 2 lightering zone. BHP Billiton will exercise caution while conducting t he proposed activities within this area.BHP Billiton Petroleum (GOM) Inc. 23 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 12 - ENVIRONMENTAL MIT IGATION MEASURES INFORMATION

(a) Impacts to Marine and Coastal Environments and Habitats, Biota, and Threatened and Endangered Species

The State of Florida is not an affected State for the activities proposed in this plan; therefore this information is not required.



### (b) Incidental Takes

BHPB does not believe that any of the endangered species or marine mammals as listed in the ESA will be taken during the development ac tivities proposed in this plan.

BHPB understands that the use of explosives or seismic devices may affe ct marine life in the vicinity. There are no operations proposed in this plan that will be using explosives or seismic

instruments.BHP Billiton Petroleum (GOM) Inc. 24 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 13 - DECOMMIS SIONING INFORMATION

This information is not required for plans submitted in the BOEM GOMR.BHP Billiton Petroleum (GOM) Inc. 25 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 14 - RELATED FACILITIES AND OPERATIONS INFORMATION

(a) Related OCS Facilities and Operations

A subsea tree will be installed with th e rig prior to leaving the location ( Attachment M ). A well jumper will be installed with an intervention vessel.

Related OCS facilities and operations were discussed in depth in the Initial Unit DOCD (Plan No. N-8542). Under this Supplemental Unit DOCD BHPB proposes to install a sled with one (1) jumper, one (1) 6.625 inch flowline and associated 4 inch umbilical from the proposed SS003 well to one of two existing inline sleds (currently designated E and F)

Description of Lease Term Pipelines

Diameter (Inches) From To Length Product Max SI Time

6 AT 574 SS003 AT 574 sled 500ft Oil 60

BOPD 45s

6 AT 574 Sled AT 574 sled 3000ft Oil 60

BOPD 45s

4 AT 574 SS003 AT 574 existing ILS 3000ft UMBH NA NA



### (b) Transportation System

Oil and gas production is exported via existing right-of-way pipelines to existing pipeline delivery systems. There will be no changes to the existing field infr astructure under this Supplemental

Plan.



### (c) Produced Liquid Hydrocarbons Transportation Vessels

There will be no produced liquid Hy drocarbons, including well test fluids, transported by means other than a pipeline for the activities proposed in this plan.BHP Billiton Petroleum (GOM) Inc. 26 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 15 - SUPPORT VESSELS AND AIRCRAFT INFORMATION

(a) General

The following list provides information regarding the vessels and aircraft BHPB will use to support our proposed development drilling and production activities.

Type of Vessel Maximum Fuel Tank Storage Capacity Maximum No. in Area at Any Time Trip Frequency or Duration during Drilling Trip Frequency or Duration during

Production

Supply boat(s) 25,000 - 370,000 gals 2 7 times / week 7 times / week

Crew boat(s) 5,000 – 15,000 gals 1 7 times / week 7 times / week

Helicopter 440 gals 1 As needed As needed

The following list provides information regarding the vessels and aircraft BHPB will use to support our proposed construction activities.

Type of Vessel Maximum Fuel Tank Storage Capacity (bbls) Maximum No. in Area at Any Time Total Duration

Installation of Risers, Flowline s, Jumpers, Manifolds, etc.

Installation Vessel (Deep Blue – flowlines, jumpers, umbilicals) 29606 1 10 days

Support vessel – subsea commissioning 11100 1 10 days



### (b) Diesel Oil Supply Vessels

BHPB proposes to use one of the following vessel(s) to supply diesel oil to support the drilling operation in this Supplemental Plan. Please note, the air emissi ons for the vessel used below is included in the air emission spreadsheets as “work/supply” vessels.

Size of Fuel Supply

Vessel Capacity of Fuel Supply Vessel (in bbls) Frequency of Fuel

Transfers Route Fuel Supply Vessel

will Take

280 ft PSV 16800 1 / month From the shorebase in Port Fourchon, LA to the MODU,

then back to shorebase

280 ft PSV 8930 2 / month From the shorebase in Port Fourchon, LA to the MODU,

then back to shorebase



### (c) Drilling Fluids Transportation

The proposed development activities do not affect the State of Florida; t herefore information on the projected drilling fluids transportation is not required at this time.



### (d) Solid and Liquid Wastes Transportation

All projected solid and liquid wastes likely to be transported during our proposed activities are included in Attachment J (Table 2).



### (e) Vicinity Map

Atwater Valley Block 574 is located approximately 114 statute miles from the nearest Louisiana shoreline and approximately 124 miles from the onshore support base located in Port Fourchon, LA.

A Vicinity Plat showing the location of the proposed development activities relative to the shoreline and

the onshore base is included as Attachment N

.BHP Billiton Petroleum (GOM) Inc. 27 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 16 - ONSHORE SUPPORT FACILITIES INFORMATION

(a) General

BHPB proposes to utilize the following existing onshore base for support:

Name Location Existing, New or Modified

Chouest Base Port Fourchon, LA Existing



### (1) Support Base Construction or Expansion

The proposed operations do not mandate any immediate measures for land acquisition or expansion of the existing onshore base facilities.



### (2) Support Base Construction or Expansion Timetable

The proposed operations do not mandate any immediate measures for land acquisition or expansion of the existing onshore base facilit ies therefore a timetable is not required.



### (b) Air Emissions

Information regarding air emissions ge nerated by onshore support facilitie s is not required to accompany plans submitted in the BOEM GOMR.



### (c) Unusual Solid and Liquid Wastes

Information regarding unusual solid and liquid wastes generated by onshore support facilities is not required to accompany plans submitted in the BOEM GOMR.



### (d) Waste Disposal

All projected solid and liquid wastes likely to be di sposed of during and after our proposed activities are

included in Attachment J (Table 2).BHP Billiton Petroleum (GOM) Inc. 28 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 17 - SULPHUR OPERATIONS INFORMATION

BHPB is not proposing to conduct su lphur operations in this plan.BHP Billiton Petroleum (GOM) Inc. 29 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 18 - COASTAL ZONE MANAGEMENT ACT (CZMA) INFORMATION

The States of Texas, Louisiana, Mississippi, Al abama and Florida have federally approved coastal zone management programs (CZMP). Applicants for an OCS plan submitted to the BOEM must provide a certification with necessary data and information for the affected State to det ermine that the proposed activity(s) complies with the enforceable policies of each States’ approved program, and that such activity will be conducted in a manner consistent with the program.



### (a) Consistency Certification

The Coastal Zone Management Consistency Certification from the State of Louisiana is not required for the development activities proposed in this Supplemental Plan.



### (b) Other Information

State of Louisiana:

The enforceable policies of the State of Louisiana have been considered and will be complied with.BHP Billiton Petroleum (GOM) Inc. 30 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 19 - ENVIRONMENTAL IMPACT ANALYSIS (EIA)

(a) And (b) BHPB has placed an “X” in each IPF category that we believe (by using good engineering judgment) would be impacted by the activity proposed in this plan.

Environmental

Resources Impact Producing Factors (IPFs) Categories and Examples

Emissions (air, noise, light, etc.) Effluents (muds, cuttings,

other discharges to

the water

column or seafloor) Physical

disturbances

to the seafloor (rig or anchor emplacements, etc.) Wastes

sent to

shore for

treatment

or disposal Accidents (e.g., oil spills,

chemical spills, H 2 S releases) Other IPFs you identify

Site-specific at Offshore

Location Designated topographic features (1) (1) (1)

Pinnacle Trend area live bottoms (2) (2) (2)

Eastern Gulf live bottoms (3) (3) (3) Chemosynthetic communities (4) (4) (4)

Water quality X X X

Fisheries X X X

Marine mammals (8) X X (8) X

Sea turtles (8) X X (8) X
Air quality (9) Shipwreck sites (known or potential) (7)
Prehistoric archaeological sites (7)

Vicinity of Offshore Location

Essential fish habitat X (6) X
Marine and pelagic birds X X X Public health and safety (5)

Coastal and Onshore

Beaches X (6) X

Wetlands (6) X Shore birds and coastal nesting

birds (6) X Coastal wildlife refuges X

Wilderness areas X

Other Resources You Identify

None

Footnotes for Environmental Impact Analysis Matrix

1. Activities that may affect a marine sanctuary or topographic fe ature. Specifically, if the well or platform site or any anc hors will be on the seafloor

within the: (a) 4-mile zone of the Flower Garden Banks, or the 3-mile zone of Stetson Bank, (b) 1000-m, 1-mile or 3-mile zone of any topographic feature (s ubmarine bank) protected by the Topographic Features Stipulation attached to an OCS lease; (c) Essential Fish Habitat (EFH) criteria of 500 ft from any no-activity zone; or (d) Proximity of any submarine bank (500 ft buffer zone) with relief greater than 2 meters that is not protected by the Topogra phic Features Stipulation attached to an OCS lease. 2. Activities with any bottom disturbance within an OCS lease block protected through the Live Bottom (Pinnacle Trend) Stipulat ion attached to an

OCS lease. 3. Activities within any Eastern Gulf OCS block where seafloor habitats are protected by the Live Bottom (Low-Relief) Stipulati on attached to an

OCS lease. 4. Activities on blocks designated by the BOEM as being in water depths 400 meters or greater. 5. Exploration or production activities where H 2 S concentrations greater than 500 ppm might be encountered. 6. All activities that could result in an accidental spill of produced liquid hydrocarbons or di esel fuel that you judge would impact these environmental resources. If the proposed action is located a sufficient distance from a resource that no impact would occur, the EIA can not e that in a sentence

or two.BHP Billiton Petroleum (GOM) Inc. 31 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 7. All activities that involve seafloor disturbances, including anchor emplacements, in any OCS block designated by the BOEM as having highprobability for the occurrence of shipwrecks or prehistoric sites, including such blocks that will be affected that are adjacen t to the lease block in which your planned activity will occur. If the proposed activities are located a sufficient distance from a shipwreck or prehi storic site that no impact would occur, the EIA can not e that in a sentence or two. 8. All activities that you determine migh t have an adverse effect on endangered or threatened marine mammals or sea turtles or their critical

habitats.

9. Production activities that involve transportation of produced fluids to shore using shuttle tankers or barges.



### (c) ANALYSIS

Site-specific at Atwater Valley Block 574



### 1. Designated Topographic Features

The topographic features of the C entral Gulf provide habitat for coral reef community organisms. Since 1973 stipulations have been made a part of leases on or near these biotic communities so that impacts from nearby oil and gas activities were mitigated to the greatest extent possible. This stipulation does not prevent the recovery of oil and gas resources, but serves to protect valuable and sensitive biological

resources.

There are no IPF’s (including effluents, physical disturba nces to the seafloor a nd accidents) that could cause impacts from the proposed development activi ties in Atwater Valley Block 574 to topographic features. The site-specific offshore location of the proposed development activities is not located near a designated topographic feature.

The activities proposed in this plan will be covered by our Regional OSRP.



### 2. Pinnacle Trend Area Live Bottoms

A small portion of the Central Planning Area and the Eastern Gulf of Mexico OCS planning areas include portions of approximately 70 lease blocks that have been classified as being within the “pinnacle trend” area. The Department of the Interior, Bure au of Ocean Energy Management, Regulation and Enforcement is the agency with ju risdiction over these leases.

The term “live bottom” is used to refer to the biol ogical assemblages attached to hard substrates found interspersed between sand and mud bottoms of the cont inental shelf. These assemblages often consist of colorful sponges, corals, sea whips and sea fans rising from the benthic environment. Some of these features have extensive vertical relief rising far into the water column and serving as a reefal habitat for numerous commercially and recreationally important fish species.

A special “Live Bottom (Pinnacle Trend) Stipulation” is assigned to leases in those blocks intended to protect the pinnacle trend and associated hard-bottom communities from damage and, at the same time, provide for recovery of potential oil and gas resources. This stipulation was not invoked with the issuance

of these leases.

There are no IPF’s (including effl uents, physical disturbances to t he seafloor, and accidents) from the proposed development activities in Atwater Valley Bloc k 574 that could cause impacts to pinnacle trend

area live bottoms.

The activities proposed in this plan will be covered by our Regional OSRPBHP Billiton Petroleum (GOM) Inc. 32 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### 3. Eastern Gulf Live Bottoms

A small portion of the Central Planning Area and the Eastern Gulf of Mexico OCS planning areas include portions of approximately 70 lease blocks that have been classified as being within the “pinnacle trend” area. The Department of the Interior, Bure au of Ocean Energy Management, Regulation and Enforcement is the agency with ju risdiction over these leases.

The term “live bottom” is used to refer to the biol ogical assemblages attached to hard substrates found interspersed between sand and mud bottoms of the cont inental shelf. These assemblages often consist of colorful sponges, corals, sea whips and sea fans rising from the benthic environment. Some of these features have extensive vertical relief rising far into the water column and serving as a reefal habitat for numerous commercially and recreationally important fish species.

A special “Live Bottom (Pinnacle Trend) Stipulation” is assigned to leases in those blocks intended to protect the pinnacle trend and associated hard-bottom communities from damage and, at the same time, provide for recovery of potential oil and gas resources. This stipulation was not invoked with the issuance

of these leases.

There are no IPF’s (including effl uents, physical disturbances to t he seafloor, and accidents) from the proposed development activities in Atwater Valley Bloc k 574 that could cause impacts to Eastern Gulf live

bottoms.

The activities proposed in this plan will be covered by our Regional OSRP.



### 4. Chemosynthetic Communities

Chemosynthetic communities are defined as persistent, largely sessile assemblages of marine organisms dependent upon chemosynthetic bacteria as thei r primary found source (MacDonald, 1992). Chemosynthetic clams, mussels, and tubeworms have been discovered in association with hydrocarbon seeps in the northern Gulf of Mexico. Initial discov eries of cold-water seep communities indicated that they are primarily associated with hydrocarbon and H 2 S seep areas (Kennicutt and Gallaway, 1985; Brooks et al., 1986a). Since the initial discovery in 1986 of chemosynthetic communities dependent on hydrocarbon seepage in the Gulf of Mexico, their g eographic range has been found to include the Texas, Louisiana and Alabama continental slope with a depth range varying from less than 500 m to 2200 m (MacDonald, 1992). To date, there are 43 sites (in 40 blocks) across the northern Gulf of Mexico continental slope where the presence of chemos ynthetic metazoans (dependent on hydrocarbon seepage) has been definitively documented (MacDonald, 1992).

There are no documented high-density chemosynt hetic communities in Atwater Valley Block 574 according to Notice to Lessees and Operators (NTL ) No. 2009-G40. Development activities have been carefully planned to avoid seafloor disturbance in the vicinity of features that could support high-density chemosynthetic communities.

There are no IPF’s (including effl uents, physical disturbances to t he seafloor, and accidents) from the proposed supplemental development activities in At water Valley Block 574 that could cause impacts to Chemosynthetic Communities (refer to informat ion referenced in Section 6.1, Chemosynthetic Communities).



### 5. Water Quality

There are no IPF’s (including effl uents, physical disturbances to t he seafloor, and accidents) from the proposed supplemental development activities in Atwa ter Valley Block 574 that could potentially cause impacts to water quality. The major discharges from offshore oil and gas production activities include produced water, ballast water, and uncontaminated seawater. Minor disc harges from the offshore oil and gas industry include well completion and workover fl uids; deck drainage; and other sanitary and domestic wastes, and miscellaneous discharges. Since all di scharges will be made in ac cordance with a general National Pollutant Discharge Elimination System (NPDES) permit issued by U.S. Environmental Protection Agency (USEPA), operati onal discharges are not expected to cause significant adverse impacts to water quality.BHP Billiton Petroleum (GOM) Inc. 33 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 With regards to marine trash and debris, effective January 01, 2012, the Bureau of Safety and

Environmental Enforcement iss ued BSEE NTL No. 2012-G01 pursuant to 30 CFR 250.103 and 30 CFR 550.103 to provide guidance and assist the operato rs in preventing intentional and / or accidental

introduction of trash and debris into the marine environment. With this assistance and with laws such as MARPOL-Annex V, the Marine Plasti c Pollution Research and Control Act, and regulations imposed by various agencies including the U.S. Coast Guard a nd the U.S. Environmental Protection Agency, our employees will ensure that all offshore personnel , including contractors an d other support servicesrelated personnel have complete un derstanding of the requirement that Operators be proactive in avoiding accidental loss of solid waste items on the OCS.

Offshore accidents, such as blowouts and spills coul d also occur and have the potential to alter offshore water quality. Given the low frequency of blow outs documented by the BOEM, minimum impacts on water quality due to resuspension of sediments are expected.

Oil spills related to the proposed action are assumed to be mostly very small events (and for spills greater than 50 bbl) to occur very infrequently. It is unlikel y that an accidental oil spill would occur from the proposed development activities. If a spill were to occur, the dissolved components and small oil droplets would temporarily affect the water quality of mari ne waters. Dispersion by currents and microbial degradation would remove the oil from the water column or dilute the constituents to background levels.

The activities proposed in this plan will be covered by our Regional OSRP.



### 6. Fisheries

Effects on commercial fisheries from development acti vities associated with this plan in Atwater Valley Block 574 could come from oil sp ills and subsurface blowouts.

An accidental oil spill that may occur as a result of the proposed development has the potential to cause

some detrimental effects to fisheries. However, it is unlikely that an ac cidental surface or subsurface oil spill would occur from the proposed development activities.

Subsurface blowouts have the potential to adversely affect commercial fishery resources. Sandy sediments will be quickly redeposited within 400 m of the blowout site and finer sediments will be widely dispersed and redeposited over a period of 30 days or longer within a few thousand meters.

If a spill were to occur in open waters of the OCS proxim ate to mobile adult finfish or shellfish, the effects would likely be sublethal and the extent of damage would be reduced to the capability of adult fish and shellfish to avoid a spill, to metabolize hydrocarbons, and to excrete both metabolites and parent compounds. The effect of oil spills on fisheries is expected to ca use less than 1 percent decrease in commercial populations or in commercial fishing.

Drilling mud discharges contain chemical s toxic to marine fishes; however, this is only at concentrations 4 or 5 orders of magnitude higher than those found mo re than a few meters from the discharge point. Offshore discharges of drilling muds will dilute to background levels within 1000 meters of the discharge point and have a negligible effect on Central Gulf fisheries.

The activities proposed in this plan will be covered by our Regional OSRP.



### 7. Marine Mammals

Marine mammals may be adversely impacted by several IPF’s (including vessel traffic, noise, accidental oil spills, and loss of trash and debris), all of which could occur due to the proposed development activity in Green Canyon Blocks 609, 610, 653 or 654.BHP Billiton Petroleum (GOM) Inc. 34 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 Chronic and sporadic sublethal effects could occur that may stress and / or weaken individuals of a local group or population and make them more susceptible to infection from natural or anthropogenic sources. Few lethal effects are expected from oil spills, chance collisions with service vessels a nd ingestion of plastic material. Oil spills of any size are estimat ed to be aperiodic events that may contact cetaceans. Disturbance (e.g., noise) may stress animals, weak en their immune systems, and make them more vulnerable to parasites and diseases that normally would not be fatal.

The net result of any disturbance would depend on the size and percentage of the population affected, ecological importance of the disturbed area, environmental and biological parameters that influence an animal’s sensitivity to disturbance and stress, and the accommodation time in response to prolonged disturbance (Geraci and St. Aubin, 1980). Collision s between cetaceans and sh ips could cause serious injury or death (Laist et al., 2001). Sperm whales are one of 11 whale species that are hit commonly by ships (Laist et al., 2001). Collisions between OCS vessels and cetaceans within the project area are expected to be unusual events.

BSEE and BOEM issued JOINT NTL No. 2012-G01 pursuant to 30 CFR 250.103, 550.103 and also 250.282 and 550.282 to explain how Operators must implem ent measures to minimize the risk of vessel strikes to protected species and report observations of injured or dead protected species effective February 7, 2007. We will ensure that our contract vessel operators are aware of their requirement to report sightings of any injured or dead protected species immediately to the BOEM Protected Species Biologist by telephone.

With regards to marine tr ash and debris, effective January 1, 2012, BSEE issued BSEE NTL No. 2012-

G01 pursuant to 30 CFR 250.103 and 30 CFR 550.103 to pr ovide guidance and assist the operators in preventing intentional and / or accidental introduction of trash and debris into the marine environment.

With this assistance and with laws such as MARPOL -Annex V, the Marine Plastic Pollution Research and Control Act, and regulations imposed by various agenci es including the U.S. Coast Guard and the U.S. Environmental Protection Agency, our employees w ill ensure that all offshore personnel, including contractors and other support services-related personnel have complete understanding of the requirement that Operators be proact ive in avoiding accidental loss of solid waste items on the OCS.



### 8. Sea Turtles

IPF’s that could impact sea turtles include vessel tr affic, noise, trash and debris, and accidental oil spills.

Small numbers of turtles c ould be killed or injured by chance collisi on with service vessels or by eating indigestible trash, particularly plastic items, accidentally lost from drill rigs, production facilities, and service vessels. Drilling rigs and project vessels produce noise that could disrupt normal behavior patterns and create some stress potentially making sea turtles more susceptible to disease. Oil spills and oil-spill-response activities are potential threats that could have lethal effects on turtles. Contact with oil, consumption of oil particles, and oil-contaminated prey could seriously affect individual sea turtles. Oilspill-response planning and the habitat protection r equirements of the Oil Pollution Act of 1990 should mitigate these threats. Most OCS-related impacts on sea turtles are expected to be sublethal. Chronic sublethal effects (e.g., stress) resulting in persi stent physiological or behavioral changes and / or

avoidance of affected areas could c ause declines in survival or productivity, resulting in gradual population declines.

BSEE and BOEM issued JOINT NTL No. 2012-G01 pursuant to 30 CFR 250.103, 550.103 and also 250.282 and 550.282 to explain how Operators must implem ent measures to minimize the risk of vessel strikes to protected species and report observations of injured or dead protected species effective January 1, 2012. We will ensure that our contract vessel operators are aware of their requirement to report sightings of any injured or dead protected species immediately to the BOEM Protected Species Biologist by telephone.BHP Billiton Petroleum (GOM) Inc. 35 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 With regards to marine tr ash and debris, effective January 1, 2012, BSEE issued BSEE NTL No. 2012-

G01 pursuant to 30 CFR 250.103 and 30 CFR 550.103 to pr ovide guidance and assist the operators in preventing intentional and / or accidental introduction of trash and debris into the marine environment.

With this assistance and with laws such as MARPOL -Annex V, the Marine Plastic Pollution Research and Control Act, and regulations imposed by various agenci es including the U.S. Coast Guard and the U.S. Environmental Protection Agency, our employees w ill ensure that all offshore personnel, including contractors and other support services-related personnel have complete understanding of the requirement that Operators be proact ive in avoiding accidental loss of solid waste items on the OCS.

The activities proposed in this plan will be covered by our Regional OSRP.



### 9. Air Quality

The proposed drilling and development activities are located 114 statute miles from the nearest Louisiana

shoreline.

Although the proposed operations are temporary in natur e, there would be a limited degree of air quality degradation in the immediate vicinity. Emissions from drilling activities consist mainly of NOx and CO. These emissions are temporary in nature. Emission s of pollutants into the at mosphere from the drilling operations proposed are not expected to have signifi cant impacts on onshore air quality because of the prevailing atmospheric conditions, emission heights, emission rates, and the distance of these emissions

from the coastline.

The Projected Air Quality Emissi ons Report indicates that the BOEM exemption level will not be exceeded during the operations proposed in the Supple mental DOCD. There are no existing facilities or activities co-located with the current proposed activi ties; therefore, the Complex Total Emissions are the

same as the Plan Emissions.



### 10. Shipwreck Sites (Known or Potential)

There are no IPF’s (including physical disturbances to the seafloor) from the proposed supplemental activities in Atwater Valley Block 574 that could cause impacts to known or potential shipwreck sites. The proposed activities are not located in or adjacent to an OCS Block designated by BOEM as having highprobability for the occurrence of shipwrecks.

However, in the event items of signi ficant cultural resource potential are discovered during the proposed operations, BHPB will immediately halt all operations and notify the appropriate department at the Bureau of Ocean Energy Management for fu rther evaluation and assistance.



### 11. Prehistoric Archaeological Sites

There are no IPF’s (including physical disturbances to the seafloor) from the proposed supplemental activities in Atwater Valley Block 574 that could caus e impacts to prehistoric archaeological sites. The proposed activities are not located in or adjacent to an OCS Block designated by BOEM as having highprobability for the occurrence of pr ehistoric archaeological sites.

However, in the event items of signi ficant cultural resource potential are discovered during the proposed operations, BHPB will immediately halt all operations and notify the appropriate department at the Bureau of Ocean Energy Management for fu rther evaluation and assistance.BHP Billiton Petroleum (GOM) Inc. 36 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### Vicinity of Offshore Location:

1. Essential Fish Habitat

IPF’s that could impact essential fish habitats as a result of the proposed dev elopment operations in the Neptune Field include effluents and accidents. The major effluent discharges from offshore oil and gas production activities include produced water, ballast water, and uncontaminated seawater. Minor discharges from the offshore oil and gas industry include well completion and workover fluids; deck drainage; and other sanitary and domestic wastes, and miscellaneous discharges. Since all discharges

will be made in acco rdance with a general National Pollut ant Discharge Eliminat ion System (NPDES) permit issued by U.S. Environmental Protection Agency (USEPA), operational discharges are not expected to cause significant adverse impacts to water quality.

Offshore oil spillage from OCS operat ions is small compared with the volume of oil produced. Since 1980, OCS operators have produced about 5.5 BBO of o il, while the amount of oil spilled offshore totaled about 61,500 bbl (0.001%) or 1 bbl spilled for every 89, 500 produced. In 1994, BOEM revised its oil-spill occurrence rates for large spills (Anderson and LaBelle, 1994). An examination of the two major sources of OCS-related offshore spills (platfo rms and pipelines) shows that the greater risk of a large spill is from a pipeline. There have been no spills ≥ 1000 bbls from OCS platforms since 1980. An accidental oil spill that may occu r as a result of the proposed development activity has the potential to

cause some detrimental effects on essential fish habitat. However, it is unlikely that an accidental surface or subsurface oil spill would occur from the proposed activities.

If a spill were to occur in open waters of the OCS proxim ate to mobile adult finfish or shellfish, the effects would likely be sublethal and the extent of damage would be limited and lessened due to the capability of adult fish and shellfish to avoid a spill, to metabolize hydrocarbons, and to excrete both metabolites and parent compounds.

The activities proposed in this plan will be covered by our Regional OSRP.



### 2. Marine and Pelagic Birds

IPF’s that could impact marine and pelagic birds as a result of the proposed operations in Atwater Valley
Block 574 include air emissions, accidents and discarded trash and debris.

Emissions of pollutant into the at mosphere from the activities associated with the proposed development operations in this plan are not projected to have signi ficant impacts on air quality that could harm marine and pelagic birds because of the prevailing atmospheric conditions, emission heights, emission rates and pollutant concentrations.

An accidental oil spill that may oc cur as a result of the proposed ac tion has the potential to cause some detrimental effects on marine and pelagic birds. Some physical oiling could occur during dives, as well as secondary toxic effects through the uptake of prey.

The activities proposed in this plan will be covered by our Regional OSRP.

With regards to marine trash and debris, coastal and marine birds can commonly become entangled and

snared in discarded trash and debris. Effective January 1, 2012 BSEE issued BSEE NTL No. 2012-G01 pursuant to 30 CFR 250.103 and 30 CFR 550.103 to provide guidance and assist the operators in preventing intentional and / or accidental introduction of trash and debris into the marine environment.

With this assistance and with laws such as MARPOL -Annex V, the Marine Plastic Pollution Research and Control Act, and regulations imposed by various agenci es including the U.S. Coast Guard and the U.S. Environmental Protection Agency, our employees w ill ensure that all offshore personnel, including contractors and other support services-related personnel have complete understanding of the requirement that Operators be proact ive in avoiding accidental loss of solid waste items on the OCS.BHP Billiton Petroleum (GOM) Inc. 37 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### 3. Public Health and Safety Due to Accidents

There are no IPF’s (including an accidental H 2 S releases) from the proposed development activities in the Neptune Field that could cause impacts to public health and safety.

In accordance with 30 CFR 250.490(c), NTL’s 20 08-G04 and 2009-G27, we have submitted sufficient information to justify our request t hat the area of our proposed activities be classified by BOEM as H 2 S absent. (Refer to specific information submitted in Section 4.0 of the Plan.)



### Coastal and Onshore:

1. Beaches

There are no IPF’s (including accidents and marine trash and debris) associated with the development of the Neptune Field that could pose a major threat to the enjoyment and use of recreational beaches. The operations proposed in this plan are not projected to have significant impacts on coastal beaches.

Atwater Valley Block 574 is 114 statute miles from the nearest shoreline. In the event of an accidental oil spill, the level of response will be based on volume, weather, and the characte ristics of the product spilled. BHPB’s objectives for spill response are to en sure the safety of citizens and response personnel; control the source of the spill, have a coordinated response effor t; maximize the protection of
environmental sensitive areas; contai n, recover and remove as much of the spill product as possible; recover and rehabilitate injured wildlife; minimi ze economic impacts; and keep the general public informed of the response activities.

The activities proposed in this plan will be covered by our Regional OSRP.

With regards to marine tras h and debris, effective Janua ry 01, 2012, the BSEE issued BSEE NTL No.

2012-G01 pursuant to 30 CFR 250.103 and 30 CFR 550.103 to provide guidance and assist the operators in preventing intentional an d / or accidental introduction of trash and debris into the marine environment. With this assistance and with laws such as MARPOL-Annex V, the Marine Plastic Pollution Research and Control Act, and regulations imposed by various agencies including the U.S. Coast Guard and the U.S. Environmental Protection Agency, our employees will ensure that all offshore personnel, including contractors and other s upport services-related personnel have complete understanding of the requirement that Operators be proact ive in avoiding accidental loss of solid waste items on the OCS.



### 2. Wetlands

There are no IPF’s (including accidents) associated wi th the development of the Neptune Field that are projected to have a significant impact on wetlands.

Atwater Valley Block 574 is 114 statute miles from the nearest shoreline. In the event of an accidental oil spill, the level of response will be based on volume, weather, and the characte ristics of the product spilled. BHPB’s objectives for spill response are to en sure the safety of citizens and response personnel; control the source of the spill, have a coordinated response effor t; maximize the protection of
environmental sensitive areas; contai n, recover and remove as much of the spill product as possible; recover and rehabilitate injured wildlife; minimi ze economic impacts; and keep the general public informed of the response activities.

The activities proposed in this plan w ill be covered by our Regional OSRP.BHP Billiton Petroleum (GOM) Inc. 38 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### 3. Shore Birds and Coastal Nesting Birds

There are no IPF’s (including accidents) associated with the development of Atwater Valley Block 574 that are projected to have a significant impac t on shore birds and coastal nesting birds.

Atwater Valley Block 574 is 114 statute miles from the nearest shoreline. In the event of an accidental oil spill, the level of response will be based on volume, weather, and the characte ristics of the product spilled. BHPB’s objectives for spill response are to en sure the safety of citizens and response personnel; control the source of the spill, have a coordinated response effor t; maximize the protection of
environmental sensitive areas; contai n, recover and remove as much of the spill product as possible; recover and rehabilitate injured wildlife; minimi ze economic impacts; and keep the general public informed of the response activities.

The activities proposed in this plan w ill be covered by our Regional OSRP.



### 4. Coastal Wildlife Refuges

There are no IPF’s (including accidents) associated with the development of Atwater Valley Block 574 that are projected to have a significant impact on coastal wildlife refuges.

Atwater Valley Block 574 is 114 statute miles from the nearest shoreline. In the event of an accidental oil spill, the level of response will be based on volume, weather, and the characte ristics of the product spilled. BHPB’s objectives for spill response are to en sure the safety of citizens and response personnel; control the source of the spill, have a coordinated response effor t; maximize the protection of
environmental sensitive areas; contai n, recover and remove as much of the spill product as possible; recover and rehabilitate injured wildlife; minimi ze economic impacts; and keep the general public informed of the response activities.

The activities proposed in this plan w ill be covered by our Regional OSRP.



### 5. Wilderness Areas

There are no IPF’s (including accidents) associated with the development of Atwater Valley Block 574 that are projected to have a signifi cant impact on wilderness areas.

Atwater Valley Block 574 is 114 statute miles from the nearest shoreline. In the event of an accidental oil spill, the level of response will be based on volume, weather, and the characte ristics of the product spilled. BHPB’s objectives for spill response are to en sure the safety of citizens and response personnel; control the source of the spill, have a coordinated response effor t; maximize the protection of
environmental sensitive areas; contai n, recover and remove as much of the spill product as possible; recover and rehabilitate injured wildlife; minimi ze economic impacts; and keep the general public informed of the response activities.

The activities proposed in this plan w ill be covered by our Regional OSRP.

Other Environmental Res ources Identified: None



### (d) Environmental Hazards

The site-specific environmental conditions have been taken into account for the proposed activities under this plan. Being located in the Gulf of Mexico , all oil and gas exploratory and development operations may at sometime experience hurricane force winds, tropical storm activity and unusual surge and sea

currents.BHP Billiton Petroleum (GOM) Inc. 39 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 In accordance with requi rements set forth in Title 33 CFR 146.14 0, an Emergency Evacuation Plan (EEP) is prepared and submitted to the appropriate USCG Marine Safety Office or Unit for review and ultimate approval. This plan provides descriptions to help define the type of storm based on the winds associated with it (i.e. major gulf storm, squall, tropical depr ession, tropical storm, gale warning, storm warning, hurricane, etc). Major hurricanes (storm having wind s peeds in excess of 74 mph) in the Gulf normally

form in the southern Gulf or Caribbean Sea. Tr opical disturbances (storms having wind speeds greater than 40 mph but less than 73 mph) that originate near the facility do not provide much warning, but usually pass the rig or facility prior to attaining hurricane status.

Each tropical disturbance will be eval uated on its own merit an d the operations modifi ed accordingly. No impacts are expected on the proposed activities fr om site-specific environmental conditions.



### (e) Alternatives

There are no alternatives other than those requir ed by regulation to be considered to reduce the environmental impacts of the activities proposed in this plan.



### (f) Mitigation Measures

No mitigation measures other than those required by regulation will be considered to avoid, lessen or eliminate potential impacts on environmental resources.



### (g) Consultation

There were no outside agencies or persons consulted regarding the potential environmental impacts associated with the activities proposed under this Supplemental DOCD.



### (h) Preparer(s)

Kathy Camp K. Camp & Associates

Phone: 713.201.9627 Email: Kathy.camp@kcampassociates.com



### (i) References

BHP Billiton Petroleum (GOM) Inc. Shallow Drilli ng Hazards A ssessment prepar ed by Shawn C. Williamson on April 16, 2013

BHPB Petroleum (GOM) Inc.’s Initial Exploration Plan (Control No. N-07528) approved August 2002.

BHPB Petroleum (GOM) Inc.’s Initial Unit Development Operations Coordination Document (Control No. N-08542) approved May 3, 2006

Federal Register, Tuesday, August 30, 2005, 30 CFR Parts 250 and 282, Oil and Gas Sulphur Operations in the Outer Continental Shelf – Plans and Information; Final Rule effective September 29,

2005

Federal Register, Vol. 77, No. 163, August 22, 2012, Final Rule for Increased Safety Measures for Energy Development on the Outer Continental Shelf

Federal Register, Vol. 75, No. 198, October 14, 2010, Final Rule for Increased Safety Measures for Energy Development on the Outer Continental Shelf

NTL 2010-N06 effective June 18, 2010 for Informati on Requirements for Exploration Plans, Development and Production Plans, and Development Operations Coordination Documents on the OCSBHP Billiton Petroleum (GOM) Inc. 40 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 NTL 2009-G40 effective January 27, 2010 for Deepwater Benthic Communities

NTL 2009-G39 effective January 27, 2010 for Biologi cally-Sensitive Underwater Features and Areas

NTL 2009-G27 effective September 9, 2009 for S ubmitting Exploration Plans and Development Operations Coordination Documents

NTL 2008-G04 effective May 1, 2008 for Information Requirements for Exploration Plans and Development Operations Coordination Documents

BSEE NTL No. 2012-G01 effective January 1, 2012 for Marine Trash and De bris Awareness and

Elimination

JOINT NTL No. 2012-G01 effective January 1, 2012 for Vessel Strike Avoidance and Injured / Dead Protected Species Reporting

Final EIS, Western Planning Area Sales (204, 2 07, 210, 215 & 218), and Central Planning Area Sales (025, 206, 208, 213, 216 & 222)

Marine Mammal Protection Act of 1972 (MMPA)

Endangered Species Act of 1973 (ESA)BHP Billiton Petroleum (GOM) Inc. 41 Atwater Valley Block 574 Supplemental DOCD Lease OCS-G 08035 

### SECTION 20 - ADMINISTRATIVE INFORMATION

(a) Exempted Information Description (Public Information Copies Only)

In accordance with 43 CFR Part 2, Appendix E, secti ons (4) and (9), the following information is exempt

from disclosure and has been omitted from t he Public Information copy of this plan:

 The geologic objectives, BHL, TVD, and MD information on form BOEM-137 (OCS Plan Information Form) in Attachment A

 All items under Geological and Geophysical Informat ion, except for the non-proprietary version of

shallow hazards assessment

 Correlative well information used to justify H2S classification request under Hydrogen Sulfide

Information



### (b) Bibliography

BHP Billiton Petroleum (GOM) Inc. Shallow Drilli ng Hazards A ssessment prepar ed by Shawn C. Williamson on April 16, 2013

BHPB Petroleum (GOM) Inc.’s Initial Exploration Plan (Control No. N-07528) approved August 2002.

BHPB Petroleum (GOM) Inc.’s Initial Unit Development Operations Coordination Document (Control No. N-08542) approved May 3, 2006

### U.S. Department of the Interior OMB Control Number: 1010-0151 

### Bureau of Ocean Energy Management OMB Approval Expires: 12/31/14



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FORM BOEM-0137 (December 2011 - Supersedes all previous editions of this form which may not be used. Page 1 of 4

###  



## PROPRIETARY COPY 

## A TTACHMENT A

REV 07-02-2013

REV 09-23-2013

### OCS PLAN INFORMATION FORM (CONTINUED)
Include one copy of this page for each proposed well/structure Proposed Well/Structure Location
Well or Structure Name / Number (if renaming well or structure, reference previous name) SS003 Previously reviewed und er an approved EP or

DOCD? Yes

X No

Is this an existing well or

structure? Yes X No If this is an existing well or structure, list the Complex ID or API No. Complex ID.

Do you plan to use a subsea BOP or a surface BOP on a floating facility to conduct your proposed activities? X Yes No

WCD info For wells, volume of uncontrolled blowout (Bbls/day) 2 9 13 0 For structures, vol ume of all storage and pipelines (Bbls) API Gravity of

fluid 21.3

Surface Location Bottom-Hole Location (For Wells) Completion (For multiple completions, enter separate lines)

Lease No. G-080 3 5

Area Name AT

Block No. 574

Block Line Departures (in feet) N/S Departure: 5201.00 FSL N/S Depart ure: F____L N/S Departu re: F____L N/S Departure: F____L
E/W Departure: 2999.00 FEL E/W Depart ure: F____L E/W Departure: F____L E/W Departure: F____L

Lambert X-Y

coordinates X: 725,641.00 X X:

X:

X:
Y: 9,936,881.00 Y:

Y:

Y:

Latitude / Longitude Latitude: 27o 21’ 18.895”N Latitud e: Latitude : Latitude:
Longitude: 89o 49’ 06.586”W Longi tude: Longit ude: Longitude: Water Depth (Feet): 6153 MD (Feet): TVD (Feet): MD (Feet): MD (Feet): MD (Feet): TVD (Feet): TVD (Feet): TVD (Feet): Anchor Radius (if applicable) in feet:

NONE 

### Anchor Locations for Drilling Rig or Construction Barge (If anchor radius supplied above, not necessary)

Anchor Name

or No. Area Block X Coordinate Y Coordinate Length of Anchor Chain on Seafloor

X= Y=

X= Y=

X= Y=

X= Y=

X= Y=

X= Y=

X= Y=

X= Y=

FORM BOEM-0137 (December 2011- Supersedes all previous editions of this form which may not be used.) Page 2 of 4

### OCS PLAN INFORMATION FORM (CONTINUED)

Provide the following information for the well with the highest Worst Case Discharge volume:

Worst Case Discharge (WCD) Well Information

WCD Well

Name Surface

Lease Surface

Area/Block Bottom

Lease Bottom

Area/Block Product Type MD TVD



### Analog Well(s)

Area/Block OCS Lease Well No. API No.



### Geologic Data for WCD

Open Hole Interval for WCD
Top (TVD in feet) Base (TVD in feet)



### Sand 1 Sand 2 Sand 3 Sand 4 Sand 5

Formation Data

Sand Name
Estimated Top TVD

Estimated Base TVD
Estimated Net Sand Height MD (Net Pay if hydrocarbon) Estimated Net Sand Height TVT (net Pay if hydrocarbon)

Fluid Type

Used in WCD? (Yes/No)



### Seismic Survey Used

Seismic Depth Volume



### Engineering Data for WCD

WCD Engineering Items

WCD (STB/Day)

WCD Calculated at

Flow Correlation
Outlet Pressure (Psia)

Gas Turbulence Factor

Software Model Used



### Sand 1 Sand 2 Sand 3 Sand 4 Sand 5

Formation Data

Sand Name
Permeability (mD)
Initial Pressure (PSIA)

FORM BOEM-0137 (December 2011- Supersedes all previous editions of this form which may not be used.) Page 3 of 4

### OCS PLAN INFORMATION FORM (CONTINUED)

Sand 1 Sand 2 Sand 3 Sand 4 Sand 5

Formation Data

Reservoir Temperature (F) Porosity (0.00)
Water Saturation (0.00) Rock Compressibility (microsips) Water Salinity (ppm)

Drive Mechanism Drainage Area (acres)



### Oil Reservoir Data

Bubble Point Pressure (PSIA)

Initial Bo (RB/STB)

Bo (RB/STB) @ Bubble Point

Rsi (SCF/STB)

Initial Oil Viscosity (Cp)

Oil Viscosity (CP) @ Bubble

Point Oil Compressibility (1/PSIA)

Oil API Gravity (API)

Specific Gas Gravity (0.00)



### Gas Reservoir Data

Condensate API Gravity
(API) Specific Gas Gravity (0.00)

Yield (STB/MMCF)



### Source of Permeability Used

Permeability from MDT Permeability from Core Analysis Percussion core Rotary sidewall core: Conventional core: Pressure Transient Analysis Permeability from CMR or NMR log analysis Permeability from other source



### Provide Model Input Values for Relative Permeability:

Residual Oil to Gas fraction (=1-Slc-Swc)
Residual Oil to Water fraction (=Soc) Critical Gas fraction (Sgc, Gas/Oil-Water Systems) Residual Gas to Water fraction (Sgc, Gas/Gas-Water Systems) Kro Oil Curve Endpoint (fraction of absolute permeability) Krg Gas Curve Endpoint (fraction of absolute permeability) Krw Water Curve Endpoint (fraction of absolute permeability)

Paperwork Reduction Act of 1995 Statement: The Paperwork Reduction Act of 1995 (44 U.S.C. 2501 et seq.) requires us to inform you that BOEM collects this inform ation as part of an applicant’s Exploration Plan or Development Operations Coordinatio n Document submitted for BOEM approval. We use the information to facilitate our review and data entry for OCS plans. We will protect proprietary data according to the Freedom of Informati on Act and 30 CFR 550.197. An agency may not conduct or sponsor, and a person is not required to respond to, a collection of inform ation unless it displays a currently valid Office of Manageme nt and Budget Control Number. Responses are mandatory (43 U.S.C. 1334). The public reporting burden for this form is included in the burden for preparing Exploration Plans and Development Operations Coordination Documents. We estimate that burden to average 600 hours with an accompanying EP, or 700 hours with an accompanying DPP or DOCD, including the time for reviewing instructions, gathering and maintaining data, and completing and reviewing the forms associated with subpart B. Direct comments regarding the burden estimate or any other aspect of this form to the Information Collection Clearance Officer, Bureau of Ocean Energy Management, 381 Elden Street, Herndon, VA 20170.

FORM BOEM-0137 (December 2011- Supersedes all previous editions of this form which may not be used.) Page 4 of 450

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### BLOCK 574, ATWATER VALLEY, GULF OF MEXICO PROPOSED AT 574 SS03 LOCATION WATER DEPTH AND SEAFLOOR FEATURES MAP AT 574

SS03 801 

### Kathy Camp

Subject: FW: Pay.gov Payment Confirmation: BOEM Development/DOCD Plan - BD



### Your payment has been submitted to Pay.gov and the details are below. If you have any questions or you wish to cancel

this payment, please contact Wendy Yanez at (504) 736

‐ 2818.

Application Name: BOEM Development/DOCD Plan
‐ BD Pay.gov Tracking ID: 25AGFEI3 Agency Tracking ID:

74441013830 Transaction Type: Sale Transaction Date: Apr 25, 20 13 2:44:36 PM

Account Holder Name: Susan Wilson

Transaction Amount: $4,238.00

Billing Address: 1360 Post Oak Blvd
Billing Address 2: Suite 150

City: Houston State/Province: TX Zip/Postal Code: 77056

Country: USA

Card Type: AmericanExpress

Card Number: ************1009

Region: Gulf of Mexico

Contact: Susan Wilson 713

‐ 599

‐ 6349

Company Na me/No: BHP Billiton Petroleum (GOM) Inc., 02010 Lease Number(s): 08035,

, , , Area

‐ Block: Atwater Valley AT, 574:

, :
, :
, :
, Type

‐ Wells: Supplemental Plan, 1

THIS IS AN AUTOMATED MESSAGE. PLEASE DO NOT REPLY.1 Site Clearance Letter - Neptune AT 574 SS03 Location Atwater Valley Block 57 4 (OCS -G- 08035 )

The tophole prognosis chart ( Figure 6 ) summarizes the shallow hazards assessment of a verti cal

well at the proposed AT 574 SS03 surface location down to 1.5 sec TWT BML (~ 5,049 ft BML). The proposed AT 574 SS03 location is in the southea st quadrant of Atwater Valley Block 57 4 as defined by the following coordinates (UTM Zone 1 6 North Projection, Clarke 1866 Spheroid, NAD 1927 Datum):

Proposed

Location Block Latitude Longitude Easting X (feet) Northing Y (feet) Block Calls (feet)

AT 574

SS03 AT 574 27° 21' 18.895" N 89° 49' 06.586" W 725,641 9,936,881 5,201

FSL 2,999

FEL

The predicted water depth at the proposed AT 574 SS03 location is 6,153 ft based on AUV multi

beam bathymetry ( Map 1 B ). The local seafloor gradient is approximately 2o to the south

- southeast

. The

closest man

- made feature to AT 574 SS03 is a 7” umbilical approximately 500 ft to the south

- southwest. The closest flowline is approximately 1

, 490 ft north of AT 574 SS03 and the closest wellhead is SC004 approximately 2

, 660 f t to the south

- southeast

.

The AUV side

- scan sonar data shows no evidence of seafloor debris in the vicinity of the proposed location ( Map 3B ). The closest sonar conta ct identified in the 2013 GEMS Archaeological Assessment is Contact 62, which is linear, approximately 2

, 040 ft to the east, and interpreted to represent

modern debris associated with storm events, exploration, development, or fishing activities.

The pr oposed AT 574 SS03 surface location is on the margin of a zone of generally parallel seafloor furrows ( Map 1B ). A zone of paleo

- erosion has been delineated approximately 1380 ft east of the proposed location.

There are no hydrocarbon macro

- seeps or hard bottom areas capable of supporting high

- density benthic communities within 2,000 ft of the AT 574 SS03 location. The closest seafloor expulsion fea ture

with elevated reflectivity in the AUV side

- scan sonar and backscatter data is approximately 6,700 ft to the

northeast (Maps 1A

, 3A , and 4A ) . Th is feature s is an elongate area comprised of two mounds interpreted to be represent hydrocarbon seep sites.

Figure 3 is a data example from a portion of the subbottom profiler record for AUV Line 1 28

, which is approximately 260 ft southwest of the proposed AT 574 SS03 locat ion

. Two re gional marke r horizons (M1 and M2 ) are annotated on this figure . Age

- dating results from the Neptune and Atlantis geotechnical investigations indicate that these horizons are approximately 1 6,434 and 19, 75 0 years old, respectively. Horizon M2 marks the top of the “Triplet”, which is a distinct set of strong reflectors that represent a regional unit containing several silt

- rich layers. The shallow sediments are expected to be predominantly clay with occasional thin silt seams to at least 1 70 f t BML.

Figure 2 is an arbitrary 3

- D seismic line correlating the AT 574 SS03 location with the existing Neptune 5 (aka SC 001 ) well

. Fig ure 4 displays 3

- D seismic data examples of the inline and crossline through the proposed location. LWD logs from Neptune 5 and other wells in the area indicate th at sands are likely between Horizons A and B, Horizons C and D, and below Horizon E ( Figure 6 ) . Sands and

cherts have been encountered below Horizon F at offset wells.

No faults intersect the proposed vertical wellbore in the tophole section. No free

- phase gas is expected in the tophole section. There are no BSR’s or other seismic indications of gas hydrate evident in the vicinity of the proposed AT 574 SS03 location

.

The AT 574 SS03 location was carefully chosen to avoid high amplitude anomalies in the tophole section. The closest high amplitude anomaly is approximately 75 0 ft north

- northwest of the proposed

location ( Figure 5 ) and is associated with Horizon E

. AT 574 SS03 is assessed to have negligible gas potential between Seafloor and Horizon A ( Figure 6 ). The remainder of the tophole section is assessed to

have low gas potential at the proposed location

. It should be noted that the 3D seismic amplitude2 respo nse is attenuated below approximately 3.5 sec TWT at the proposed location (annotated as Reduced Seismic Image Quality on Figure 6 ). Nonetheless, detailed analysis of amplitude extraction s

across this interval indicated no obvious gas anomalies.

Shallow water flow was observed at the Neptune 6 well and is suspected to have occurred at the Neptune 1 well. The AT 574 SS03 location is assessed to have moderate SWF potential in the interpreted

sand

- bearing intervals between Horizons C and D, and below Horizon E ( Figure 6 ) assuming no mitigation measures are in place. Low SWF potential is assessed for the intervals between Horizons A and C, and Horizons D and E. The SWF potential is negligible for the clay

- prone unit above Horizon A.

Seafloor and shallow subsurface conditions are favorable for drilling operations at AT 574 SS03

. Standard drilling precautions successfully utilized at previo us Neptune wells should be taken to mitigate

SWF potential associated with interpreted sandy intervals below Horizon A . An anchor clearance

assessment should be conducted if the well is drilled from a moored vessel.

BHP Billiton Petroleum (GOM) Inc.

S

T

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A

SP R O F E S S I O

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I E N T I ST

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I C E N S E D Shawn C. Williamson

Geology

382 S

T

A

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E O F T E X

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SP R O F E S S I O

N

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I E N T I ST

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I C E N S E D Shawn C. Williamson

Geology

382 S

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E O F T E X

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SP R O F E S S I O

N

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L G E O

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I C E N S E D Shawn C. Williamson

Geology

382

Shawn C. Williamson, P.G. Geohazards Interpreter April 16, 2013

Attachments

• Figure 1: 3

- D Seismic Power Spectrum

– Proposed AT 574 SS03 Location

• Figure 2 : Arbitrary 3D and 2DHR ( Line 31 ) Seismic Profiles from Proposed AT 574 SS03 Locatio n
to Existing Neptune 5 Well

• Figure 3 : AUV Subbottom Profile

– Portion of L ine 1 28 Nearest the Proposed AT 574 SS03

Location

• Figure 4 : 3D Seismic Inline 3533 and Crossline 4024 Through the Proposed AT 574 SS03

Location

• Figure 5 : Interval Amplitude Extraction Seafloor to 1.5 sec TWT BML

– Proposed AT 574 SS03

Location

• Figure 6: Tophole Prognosis Chart

– Proposed AT 574 SS03 Location

• Map 1 A : Water Depth and Seafloor Features Map
– Neptune Field

• Map 1B: Water Depth and Seafloor Features Map

– Proposed AT 574 SS03 Location

• Map 2 A : Seafloor Rendering

– Neptune Field

• Map 2B: Seafloor Rendering

– Proposed AT 574 SS03 Location

• Map 3 A : Side

- Scan Sonar Mosaic

– Neptune Field

• Map 3B: Side

- Scan Sonar Mosaic

– Proposed AT 574 SS03 Location

• Map 4 A : Seafloor Backscatter Map
– Neptune Field

• Map 4B: Seafloor Backscatter Map

– Proposed AT 574 SS03 Location50

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### BLOCK 574, ATWATER VALLEY, GULF OF MEXICO PROPOSED AT 574 SS03 LOCATION WATER DEPTH AND SEAFLOOR FEATURES MAP AT 574

SS03 80Neptune AT 574 SS03 Relief WellShallow Hazards Screening Map withBathymetry Contour Overlay (C.I.=10 ft)Slide 1SC004SC003SC002SC001 (Neptune 5)AT 575-1 (Neptune 1) Seafloor Gradient (degrees)Possible Gas Anomalies5000-ft-radiusAmount is per wellProjected generated wasteType of WasteCompositionProjected Amount Discharge rate Discharge MethodAnswerYes or NoWill drilling occur ? If yes, you should list muds and cuttingsWater-based drilling fluidNaCl brine; Evaporated Salt;Xanthan Gum; Barite16,035 bbls 146 bbl/day overboard / seafloorNoCuttings wetted with water-based fluidCuttings wetted with seawater,gel, and 10.5 ppg fresh waterpad mud residue from riserlesshole sections2,133 bbls19 bbl/day seafloorNoSynthetic-based drilling fluid amount adhere to cuttings Baroid Accolade SBM1,703 bbls15bbl/day overboardNoCuttings wetted with synthetic-based fluidCuttings wetted with residue ofBaroid Accolade SBM2,840 bbls26 bbl/day overboardNoWill humans be there? If yes, expect conventional wasteDomestic wasteKitchen waste30,250 bbls 275 bbl/day remove floating solidsand dischargeNoSanitary wasteSanitary waste8,690 bbls79 bbl/day chlorinate and dischargeNoIs there a deck? If yes, there will be Deck DrainageDeck DrainageRainfall & potable water19,800 bbls 180 bbl/day filter oil and grease anddischargeNoWill you conduct well treatment,completion, or workover?Well treatment fluidsNANANANANAWell completion fluidsWater Based fluids and SeaWater1,893 bbls17 bbl/day discharge used fluidsoverboardNoWorkover fluidsNANANANANAMiscellaneous discharges. If yes, only fill in thoseassociated with your activity.Desalinization unit dischargeMax capacity2,707,320 bbls 24,612 bbl/day overboardNoBlowout prevent fluidStack Magic ECO-FV25,500 bbls50 bbl/day overboardNoBallast waterSea Water129,250 bbls 1,175 bbl/day overboardNoBilge waterOil/Water Mixture2,750 bbls25 bbl/day 0<15ppm overboardNoExcess cement at seafloorClass H764 bbls7 bbl/day seafloorNoFire waterSea Water797,500 bbls 7,250 bbl/day overboardNoCooling waterSea Water49,484,600 bbls 449,860 bbl/day overboardNoWill you produce hydrocarbons? If yes fill in for produced water.Produced waterNANANANANAWill you be covered by an individual or general NPDES permit ?General PermitNOTE: If you will not have a type of waste, enter NA in the row.ProjectedDownholeDisposalProjectedOceanDischargesplease specify if the amount reported is a total or per well amountTABLE 1. WASTES YOU WILL GENERATE, TREAT AND DOWNHOLE DISPOSE OR DISCHARGE TOTHE GOM - C.R. Luigsplease specify whether the amount reported is a total or per welRIG = CRLProjectedgenerated wasteSolidandLiquidWastestransportationType of WasteCompositionTransport MethodName/Location of FacilityAmountDisposal MethodWill drilling occur ? If yes, fill in the muds and cuttings.EXAMPLE: Synthetic-based drilling fluid ormudinternal olefin, ester Below deck storage tanks on offshoresupport vesselsNewpark EnvironmentalServices Inc., Ingleside, TXX bbl/well RecycledCuttings wetted with Water-based fluidNANANANANAOil-based drilling fluid or mudNANANANANACuttings wetted with oil-based fluidsNANANANANASynthetic-based drilling fluid or mudWhole mud sent back in afterwell has been abandoned forreconditioning & reuseCutting boxes on offshore supportvessel to onshore dock; then trucked tofacilityBaroid facility at Fourchonshore base7500 bbls/well recycledSynthetic-based drilling fluid or mudTank washings from offshoreworkboats (9.0 ppg BaroidAccolade SBM)Below deck storage tanks on offshoresupport vesselsNewpark EnvironmentalServices Inc., Fourchon, La1750 bbls/well injectedCuttings wetted with Synthetic-based fluid * Cuttings wetted with residueof Baroid 9.0 ppg AccoladeCuttings boxes on offshore supportvesselsNewpark EnvironmentalServices Inc., Fourchon, La750 bbls/well injectedWill you produce hydrocarbons? If yes fill in for produced sand.Produced sandNANANANANATrash and debrisnon-recyclable / nonhazardous refuse generatedby personnel on boardMODUtransport in bags / baskets on vessel toshorebase - picked up at shorebaseand trucked to private facilityRiver Birch Landfill inAvondale, LA via GallianoWaste Disposal in Galliano,LA150 cu yds LandfillTrash and debrisnon-hazardous recyclablesand scrap metaltransport in bags / baskets on vessel toshorebase - picked up at shorebaseand trucked to private facilityARC in New Iberia, LA 78125 lbs RecycleWaste and Used oiloil filters, rags, pads, emptydrumstransfer for recycle or fuel blending L&L Oilfield Services inFourchon, LA or SafetyKleen Systems, Inc. transferfacility in Kenner, LA500 bbls Recycle or fuelblendWash waterwater with trace amounts ofinternal olefin & esterPicked up at shorebase & trucked toprivate facilityNewpark EnvironmentalServices Inc., Fourchon, La1000 bbls injectedChemical product wastesNANANANANANOTE: If you will not have a type of waste, enter NA in the row.Waste DisposalTABLE 2. WASTES YOU WILL TRANSPORT AND/OR DISPOSE OF ONSHOREWill you have additional wastes that are not permitted for discharge? If yes,fill in the appropriate rows.NOTE: * This corresponds to the cuttings wetted with systetic base fluid that are captured in cutting boxes if the per well average limit of 6.9% ROC by weight is forecasted to be exceeded or inthe event that "Tar" is encountered and "Zero" descharge is required.Amount is per wellProjected generated wasteType of WasteCompositionProjected Amount Discharge rate Discharge MethodAnswerYes or NoWill drilling occur ? If yes, you should list muds and cuttingsWater-based drilling fluidNaCl brine; Evaporated Salt;Xanthan Gum; Barite16,035 bbls 146 bbl/day overboard / seafloorNoCuttings wetted with water-based fluidCuttings wetted with seawater,gel, and 10.5 ppg fresh waterpad mud residue from riserlesshole sections2,133 bbls19 bbl/day seafloorNoSynthetic-based drilling fluid (amountadhering tocuttings)Baroid Accolade SBM1,703 bbls15 bbl/day overboardNoCuttings wetted with synthetic-based fluidCuttings wetted with residue ofBaroid Accolade SBM2,840 bbls26 bbl/day overboardNoWill humans be there? If yes, expect conventional wasteDomestic wasteKitchen waste38,500 bbls 350 bbl/day remove floating solidsand dischargeNoSanitary wasteSanitary waste11,000 bbls 100 bbl/day chlorinate and dischargeNoIs there a deck? If yes, there will be Deck DrainageDeck DrainageRainfall & potable water19,800 bbls 180 bbl/day filter oil and grease anddischargeNoWill you conduct well treatment,completion, or workover?Well treatment fluidsNA0NANANoWell completion fluidsWater Based fluids and SeaWater1,893 bbls17 bbl/day discharge used fluidsoverboardNoWorkover fluidsNANANANANoMiscellaneous discharges. If yes, only fill in thoseassociated with your activity.Desalinization unit dischargeMax capacity1,439,790 bbls 13,089 bbl/day overboardNoBlowout prevent fluidStack Magic ECO-FV22,343 bbls21 bbl/day overboardNoBallast waterSea Water27,665 bbls 252 bbl/day overboardNoBilge waterOil/Water Mixture330 bbls3 bbl/day 0<15ppm overboardNoExcess cement at seafloorClass H764 bbls8 bbl/min seafloorNoFire waterSea Water6,600 bbls60 bbl/day overboardNoCooling waterSea Water87,307,770 bbls 793,707 bbl/day overboardNoWill you produce hydrocarbons? If yes fill in for produced water.Produced waterNANANANANoWill you be covered by an individual or general NPDES permit ?General PermitNOTE: If you will not have a type of waste, enter NA in the row.ProjectedDownholeDisposalProjectedOceanDischargesplease specify if the amount reported is a total or per well amountTABLE 1. WASTES YOU WILL GENERATE, TREAT AND DOWNHOLE DISPOSE OR DISCHARGE TOTHE GOM - Development Driller 1please specify whether the amount reported is a total or per welRIG = DD1Projectedgenerated wasteSolidandLiquidWastestransportationType of WasteCompositionTransport MethodName/Location of FacilityAmountDisposal MethodWill drilling occur ? If yes, fill in the muds and cuttings.EXAMPLE: Synthetic-based drilling fluid ormudinternal olefin, ester Below deck storage tanks on offshoresupport vesselsNewpark EnvironmentalServices Inc., Ingleside, TXX bbl/well RecycledCuttings wetted with Water-based fluidNANANANANAOil-based drilling fluid or mudNANANANANACuttings wetted with oil-based fluidsNANANANANASynthetic-based drilling fluid or mudWhole mud sent back in afterwell has been abandoned forreconditioning & reuseCutting boxes on offshore supportvessel to onshore dock; then trucked tofacilityBaroid facility at Fourchonshore base7500 bbls/well recycledSynthetic-based drilling fluid or mudTank washings from offshoreworkboats (9.0 ppg BaroidAccolade SBM)Below deck storage tanks on offshoresupport vesselsNewpark EnvironmentalServices Inc., Fourchon, La1750 bbls/well injectedCuttings wetted with Synthetic-based fluid * Cuttings wetted with residueof Baroid 9.0 ppg AccoladeCuttings boxes on offshore supportvesselsNewpark EnvironmentalServices Inc., Fourchon, La750 bbls/well injectedWill you produce hydrocarbons? If yes fill in for produced sand.Produced sandNANANANANATrash and debrisnon-recyclable / nonhazardous refuse generatedby personnel on boardMODUtransport in bags / baskets on vessel toshorebase - picked up at shorebaseand trucked to private facilityRiver Birch Landfill inAvondale, LA via GallianoWaste Disposal in Galliano,LA150 cu yds LandfillTrash and debrisnon-hazardous recyclablesand scrap metaltransport in bags / baskets on vessel toshorebase - picked up at shorebaseand trucked to private facilityARC in New Iberia, LA 78125 lbs RecycleWaste and Used oiloil filters, rags, pads, emptydrumstransfer for recycle or fuel blending L&L Oilfield Services inFourchon, LA or SafetyKleen Systems, Inc. transferfacility in Kenner, LA500 bbls Recycle or fuelblendWash waterwater with trace amounts ofinternal olefin & esterPicked up at shorebase & trucked toprivate facilityNewpark EnvironmentalServices Inc., Fourchon, La1000 bbls injectedChemical product wastesNANANANANAWaste DisposalTABLE 2. WASTES YOU WILL TRANSPORT AND/OR DISPOSE OF ONSHOREWill you have additional wastes that are not permitted for discharge? If yes,fill in the appropriate rows.NOTE: * This corresponds to the cuttings wetted with systetic base fluid that are captured in cutting boxes if the per well average limit of 6.9% ROC by weight is forecasted to be exceeded or inthe event that "Tar" is encountered and "Zero" descharge is required.OMB Control No. 1010-0151OMB Approval Expires: 12/31/2011COMPANYBHP Billiton Pet. (GOM) Inc.AREAAtwater ValleyBLOCK574LEASEOCS-G 08035PLATFORMWELLSS003COMPANY CONTACTKathy CampTELEPHONE NO.713.201.9627REMARKSDrill / complete Well SS003with CRL / Commence productionLEASE TERM PIPELINE CONSTRUCTION INFORMATION:YEARNUMBER OFTOTAL NUMBER OF CONSTRUCTION DAYSPIPELINES2014310FORM BOEM-139(October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used).Page 1 of 8EMISSIONS FACTORS

Fuel Usage Conversion Factors Natural Gas Turbines Natural Gas Engines Diesel Recip. Engine REF. DATE
SCF/hp-hr 9.524 SCF/hp-hr 7.143 GAL/hp-hr 0.0483 AP42 3.2-1 4/76 & 8/84
Btu/hp-hr 2543.5

Equipment/Emission Factors units PM SOx NOx VOC CO CO2-e [1] REF. DATE

Diesel Turbines lb/MMBtu 0.0203 0.00152 0.88 0.00803 0.0124 163.6 AP-42 3.1-2a &

Back g round 3.4-2 04/00

Diesel Recip. < 600 hp. lb/MMBtu 0.31 0.29 4.41 0.36 0.95 163.6 AP-42 3.3-1 10/96 Diesel Recip. < 600 hp. gms/hp-hr 1 0.005505 14 1.12 3.03 163.6 AP42 3.3-1 10/96

Diesel Recip. < 600 hp.-EPA Tier 1 [2] gms/kW-hr 0.54 9.2 1.3 11.4 EPA Tier 1

Diesel Recip. < 600 hp.-EPA Tier 1 [2] lb/hp-hr 0.000888 0.0151 0.00214 0.0187 EPA Tier 1

Diesel Recip. < 600 hp.-EPA Tier 2 [3] gms/kW-hr 0.2 6.4 3.5 EPA Tier 2

Diesel Recip. < 600 hp.-EPA Tier 2 [3] lb/hp-hr 0.000329 0.0109 0.00576 EPA Tier 2

Diesel Recip. < 600 hp.-EPA Tier 3 [4] gms/kW-hr 0.2 4 3.5 EPA Tier 3

Diesel Recip. < 600 hp.-EPA Tier 3 [4] lb/hp-hr 0.000329 0.00658 0.00576 EPA Tier 3

Diesel Recip. > 600 hp. lb/MMBtu 0.0573 0.001515 3.2 0.0819 0.85 163.6 AP-42 3.4-1 10/96

Diesel Recip. > 600 hp.-CRL-Main [5] g/kW-hr 17.02 2.42 COMM Test Apr-10

Diesel Recip. > 600 hp.-IMO Tier 1 (=>

2000 rpm) [6] g/kW-hr 9.8 7.2 IMO Tier 1

Diesel Recip. > 600 hp.-Marine Tier 1

(130-1999 rpm) [7] g/kW-hr 45*(N)^(-0.2) 40CFR94.8(a)( 1) 12/07

Diesel Recip. ≥ 37kw -Marine Tier 2

(displacement 1.2 L - >5.0 L/cyl.) [8] g/kW-hr 0.2 7.20 5.0 40CFR94.8(a)( 2) 12/07

Diesel Recip. > 600 hp.-DD1-Main [9] g/kW-hr 14.06 1.98 COMM Test May-10

Diesel Recip. > 600 hp. lb/hp-hr 0.0007 0.000012 0.024 0.00064155 0.0055 163.6 AP-42 3.4-1 10/96 Diesel Recip. > 600 hp. gms/hp-hr 0.32 0.005505 11 0.33 2.4 163.6 AP42 3.4-1 10/96 Duel Fuel (NG & Diesel) lb/MMBtu 0.0573 0.183150 2.7 0.02 1.16 122.6 AP-42 3.4-1 10/96 Duel Fuel (NG & Diesel) lb/hp-hr 0.0007 0.001352 0.018 0.00132 0.0075 122.6 AP-42 3.4-1 10/96

Diesel Boiler lbs/bbl 0.084 0.009075 0.84 0.008 0.21 163.6 AP-42 1.3-12,14 9/98

Sulphur Content Source Value Units

Fuel Gas 3.33 ppm

Diesel Fuel [10] 0.0015 % weight Produced Gas( Flares) 3.33 ppm Produced Oil (Liquid Flaring ) 2.86 % weight

The followin g e q uations were used in formulatin g the conversion factors used in the a pp lication p acka ge kW: h p = ( kW ) x ( 1.341 h p /kW ) . Factor = 1.341 h p /kW.

[1] The calculated emission factors for CO2-e (CO2, CH4 and N2O) are based on 40 CFR 98, Tables C-1 & C-2.

[5] Diesel Recip. > 600 hp.-CRL-Main: COMM Engineering testing of Transocean International's C.R. Luigs' (CRL) eight (8) main engines for NOx and CO was conducted April 2010.
The NOx emission factor was conservatively calculated 110% of the test average; the CO emission factor utilizes the maximum CO emission rate of the tests.

[6] Diesel Recip. > 600 hp.-IMO Tier 1 (=> 2000 rpm): NOx emission factors for IMO Tier 1 diesel engines on certain cement unit engines with rated engine rpm is equal to or greater

than 2000.

[8] Diesel Recip. ≥ 37kw -Marine Tier 2: VESSELS: EPA Marine Engine Tier 2 for marine engines maunfactured after 2004 with a per cylinder displacement of 1.2 L - >5.0 L. [7] Diesel Recip. > 600 hp.-Marine Tier 1, for NOx: 45.0 x N^(-0.20) g/kW-hr, where N is maximum/rated engine rpm from 130-1999. Vessel (Crew) maximum rpm is 1,800 per main
engine. Vessel (Work) main engines maximum rpm are 1000 rpm, and generators and SDT are 1800 rpm. [2] Diesel Recip. < 600 hp.-EPA Tier 1: PM, NOx, and CO emission factors for EPA Tier 1 diesel engines on certain wireline and cement unit engines.

[3] Diesel Recip. < 600 hp.-EPA Tier 2: PM, NOx, and CO emission factors for EPA Tier 2 diesel engines on certain wireline and cement unit engines.

[4] Diesel Recip. < 600 hp.-EPA Tier 3: PM, NOx, and CO emission factors for EPA Tier 3 diesel engines on certain wireline and cement unit engines.

FORM BOEM-139 (October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used). Page 2 of 8COMPANYAREABLOCK LEASE PLATFORM WELLCONTACTPHONEREMARKSBHP Billiton Pet. (GOM) Atwater Valley574 OCS-G 08035 0 SS003Kathy Camp713.201.9627Drill / complete Well SS003OPERATIONSEQUIPMENTRATING MAX. FUEL ACT. FUEL RUN TIMEMAXIMUM POUNDS PER HOURESTIMATED TONSDiesel EnginesHP GAL/HR GAL/DNat. Gas EnginesHPSCF/HRSCF/DBurnersMMBTU/HRSCF/HR SCF/D HR/D DAYS PM SOx NOx VOC CO CO2 PM SOx NOx VOC CO CO2DRILLINGDPDRILL SHIP[1]53417 2580.04 19924.50 24 125 39.86 0.65 1451.87 43.29 229.96 61204.61 19.24 0.31 700.76 20.89 110.99 29540.98PRIME MOVER>600hp diesel[2] [3]47000 2270.10 54482.4033.16 0.57 1315.12 34.19 186.99 53852.18 0.00 0.00 0.00 0.00 0.00 0.00CRANES<600hp diesel[4] [5]1220 58.93 1414.222.69 0.01 37.66 3.01 8.15 1397.84 0.00 0.00 0.00 0.00 0.00 0.00Emergency Generator>600hp diesel2064 99.69 2392.591.46 0.03 50.05 1.50 10.92 2364.87 0.00 0.00 0.00 0.00 0.00 0.00EMERGENCY EQUIP<600hp diesel323 15.60 374.420.71 0.00 9.97 0.80 2.16 370.08 0.00 0.00 0.00 0.00 0.00 0.00WIRELINE <600hp diesel-POSU-CA PU Eng.[6]300 14.49 347.760.10 0.00 1.97 0.74 1.73 343.73 0.00 0.00 0.00 0.00 0.00 0.00WIRELINE <600hp diesel-POSU-CA PU Eng.[6]300 14.49 347.760.10 0.00 1.97 0.74 1.73 343.73 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING <600hp diesel (Nitrogen pump)[7]490 23.67 568.010.44 0.01 7.41 1.05 9.18 561.43 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING >600hp diesel[8]860 41.54 996.910.61 0.01 13.86 0.63 4.55 985.36 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING >600hp diesel[8]860 41.54 996.910.61 0.01 13.86 0.63 4.55 985.36 0.00 0.00 0.00 0.00 0.00 0.00ECO CrewVESSELS≥37kw diesel(crew) (main-4)[9]9000 434.70 10432.80 24 125 2.96 0.11 106.53 6.55 47.62 10311.95 4.44 0.16 159.80 9.82 71.43 15467.93VESSELS≥37kw diesel(crew) (gens-3)[9]1083 52.31 1255.41 24 125 0.36 0.01 12.82 2.67 8.90 1240.87 0.53 0.02 19.23 4.01 13.35 1861.31Work/SupplyVESSELS>600hp diesel(work) (main-2)[10]13196 637.37 15296.80 24 125 9.31 0.16 245.22 9.60 69.82 15119.62 13.96 0.24 367.84 14.40 104.73 22679.422 vesselsVESSELS>600hp diesel(work) (gen.-2)[10]4881 235.76 5658.33 24 125 3.44 0.06 80.65 3.55 25.83 5592.79 5.17 0.09 120.97 5.33 38.74 8389.19VESSELS>600hp diesel(work) (SDT)[10]2200 106.26 2550.24 24 125 1.55 0.03 36.35 1.60 11.64 2520.70 2.33 0.04 54.52 2.40 17.46 3781.05VESSELS<600hp diesel(work) (E-Generator)502 24.22 581.38 24 125 1.11 0.01 15.48 1.24 3.35 574.64 1.66 0.01 23.22 1.86 5.03 861.97INSTALLATION INSTALLATION Vessel >600hp diesel47000 2270.1 54482.40 24 10 33.16 0.57 1139.80 34.19 248.68 53851.31 3.98 0.07 136.78 4.10 29.84 6462.16jumper / flowline SUPPORT VESSEL >600hp diesel17000 821.1 19706.40 24 10 11.99 0.21 412.27 12.37 89.95 19478.13 1.44 0.02 49.47 1.48 10.79 2337.38umbilical VESSELS>600hp diesel(supply)12000 579.6 13910.40 24 10 8.47 0.15 291.01 8.73 63.49 13749.27 1.02 0.02 34.92 1.05 7.62 1649.912014YEAR TOTAL (ANNUAL)152.072.59 5243.86 167.08 1029.21 244848.50 53.76 0.99 1667.51 65.35 409.99 93031.29EXEMPTIONCALCULATIONDISTANCE FROM LAND IN MILES3796.203796.203796.203796.20 79937.18114[7] Diesel Recip. < 600 hp.-EPA Tier 1: PM, NOx, VOC and CO emission factors for EPA Tier 1 diesel engines on certain cement unit engines.[1] DRILL SHIP: TOI's CRL's average daily fuel usage for the period June 1, 2011 through May 31, 2012 was 13,283 gallons/day. Actual fuel usage is conservatively estimated at 150% of this average.[2] PRIME MOVER>600hp diesel: TOI's CRL's maximum output per main engine is 5875 hp/4184 kW with normal operation involving operating four (4) of eight (8) main engines. These calculations conservatively assume operating 8 of 8 engines.[3] PRIME MOVER>600hp diesel: Based on TOI's CRL. For all pollutants except NOx and CO, the maximum hourly emissions (lbs/hr) are calculated based on the appropriate AP-42 and EPA emission factor and the total engine rating of 5875 HP (mechanical), as the AP-42 and EPA emission factors arebased on brake HP. COMM Engineering testing of Transocean International's (TOI) C.R. Luigs' (CRL) eight (8) main engines for NOx and CO was conducted April 2010. The NOx emission factor was conservatively calculated 110% of the test average; the CO emission factor utilizes the maximum COemission rate of the tests.[4] CRANES<600hp diesel: Based on TOI's CRL. Assumes operation of 4 of 4 cranes (305 hp each) at any one time.[5] CRANES<600hp diesel: Based on TOI's CRL. From TOI, each crane engine consumes 0.066 tonnes diesel /hr @ 75% load (27.32 gal per hour @ 100% load and 7.1 lb/gal.)[6] Diesel Recip. < 600 hp.-EPA Tier 3: PM, NOx, and CO emission factors for EPA Tier 3 diesel engines on certain wireline unit engines.FORM BOEM-139(October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used).Page 3 of 8SUMMARYCOMPANY AREABLOCKLEASEPLATFORM WELLBHP Billiton Pet.Atwater Valley 574OCS-G 08035 0SS003EmittedSubstanceYearPMSOxNOxVOCCO2014 53.760.991667.51 65.35409.99Allowable3796.203796.20 3796.203796.20 79937.18FORM BOEM-139(October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used).Page 8 of 8OMB Control No. 1010-0151OMB Approval Expires: 12/31/2011COMPANYBHP Billiton Pet. (GOM) Inc.AREAAtwater ValleyBLOCK574LEASEOCS-G 08035PLATFORMNAWELLSS003COMPANY CONTACTKathy CampTELEPHONE NO.713.201.9627REMARKSDrill / complete Well SS003 with DD1 / commence productionLEASE TERM PIPELINE CONSTRUCTION INFORMATION:YEAR NUMBER OF TOTAL NUMBER OF CONSTRUCTION DAYSPIPELINES2014 3 10FORM BOEM-139(October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used).Page 1 of 8EMISSIONS FACTORS

Fuel Usage Conversion Factors Natural Gas Turbines Natural Gas Engines Diesel Recip. Engine REF. DATE

SCF/hp-hr 9.524 SCF/hp-hr 7.143 GAL/hp-hr 0.0483 AP42 3.2-1 4/76 & 8/84
Btu/hp-hr 2543.5

Equipment/Emission Factors units PM SOx NOx VOC CO CO2-e [1] REF. DATE

Diesel Turbines lb/MMBtu 0.0203 0.00152 0.88 0.00803 0.0124 163.6 AP-42 3.1-2a &

Back g round 3.4-2 04/00

Diesel Recip. < 600 hp. lb/MMBtu 0.31 0.29 4.41 0.36 0.95 163.6 AP-42 3.3-1 10/96 Diesel Recip. < 600 hp. gms/hp-hr 1 0.005505 14 1.12 3.03 163.6 AP42 3.3-1 10/96

Diesel Recip. < 600 hp.-EPA Tier 1 [2] gms/kW-hr 0.54 9.2 1.3 11.4 EPA Tier 1

Diesel Recip. < 600 hp.-EPA Tier 1 [2] lb/hp-hr 0.000888 0.0151 0.00214 0.0187 EPA Tier 1

Diesel Recip. < 600 hp.-EPA Tier 2 [3] gms/kW-hr 0.2 6.4 3.5 EPA Tier 2

Diesel Recip. < 600 hp.-EPA Tier 2 [3] lb/hp-hr 0.000329 0.0109 0.00576 EPA Tier 2

Diesel Recip. < 600 hp.-EPA Tier 3 [4] gms/kW-hr 0.2 4 3.5 EPA Tier 3

Diesel Recip. < 600 hp.-EPA Tier 3 [4] lb/hp-hr 0.000329 0.00658 0.00576 EPA Tier 3

Diesel Recip. > 600 hp. lb/MMBtu 0.0573 0.001515 3.2 0.0819 0.85 163.6 AP-42 3.4-1 10/96

Diesel Recip. > 600 hp.-CRL-Main [5] g/kW-hr 17.02 2.42 COMM Test Apr-10

Diesel Recip. > 600 hp.-IMO Tier 1 (=>

2000 rpm) [6] g/kW-hr 9.8 7.2 IMO Tier 1

Diesel Recip. > 600 hp.-Marine Tier 1

(130-1999 rpm) [7] g/kW-hr 45*(N)^(-0.2) 40CFR94.8(a)( 1) 12/07

Diesel Recip. ≥ 37kw -Marine Tier 2

(displacement 1.2 L - >5.0 L/cyl.) [8] g/kW-hr 0.2 7.20 5.0 40CFR94.8(a)( 2) 12/07

Diesel Recip. > 600 hp.-DD1-Main [9] g/kW-hr 14.06 1.98 COMM Test May-10

Diesel Recip. > 600 hp. lb/hp-hr 0.0007 0.000012 0.024 0.00064155 0.0055 163.6 AP-42 3.4-1 10/96 Diesel Recip. > 600 hp. gms/hp-hr 0.32 0.005505 11 0.33 2.4 163.6 AP42 3.4-1 10/96 Duel Fuel (NG & Diesel) lb/MMBtu 0.0573 0.183150 2.7 0.02 1.16 122.6 AP-42 3.4-1 10/96 Duel Fuel (NG & Diesel) lb/hp-hr 0.0007 0.001352 0.018 0.00132 0.0075 122.6 AP-42 3.4-1 10/96

Diesel Boiler lbs/bbl 0.084 0.009075 0.84 0.008 0.21 163.6 AP-42 1.3-12,14 9/98

Sulphur Content Source Value Units

Fuel Gas 3.33 ppm

Diesel Fuel [10] 0.0015 % weight Produced Gas( Flares) 3.33 ppm Produced Oil (Liquid Flaring ) 2.86 % weight

The followin g e q uations were used in formulatin g the conversion factors used in the a pp lication p acka ge kW: h p = ( kW ) x ( 1.341 h p /kW ) . Factor = 1.341 h p /kW.

[10] BHPB utilizes Low Sulfur Diesel for all diesel combustion sources. Therefore, SO2 emissions have been calculated based on a maximum sulfur content of 500 ppm in diesel fuel
assuming that 100 percent of sulfur in the fuel is oxidized to SO2. [9] Diesel Recip. > 600 hp.-DD1-Main: COMM Engineering testing of Transocean International's Development Driller 1 (DD-1) eight (8) main engines for NOx and CO was conducted
May 2010. The NOx & CO emission factors conservatively utilized the maximum NOx and CO emission rates of the tests. [1] The calculated emission factors for CO2-e (CO2, CH4 and N2O) are based on 40 CFR 98, Tables C-1 & C-2.

[5] Diesel Recip. > 600 hp.-CRL-Main: COMM Engineering testing of Transocean International's C.R. Luigs' (CRL) eight (8) main engines for NOx and CO was conducted April 2010.
The NOx emission factor was conservatively calculated 110% of the test average; the CO emission factor utilizes the maximum CO emission rate of the tests.

[6] Diesel Recip. > 600 hp.-IMO Tier 1 (=> 2000 rpm): NOx emission factors for IMO Tier 1 diesel engines on certain cement unit engines with rated engine rpm is equal to or greater

than 2000.

[8] Diesel Recip. ≥ 37kw -Marine Tier 2: VESSELS: EPA Marine Engine Tier 2 for marine engines maunfactured after 2004 with a per cylinder displacement of 1.2 L - >5.0 L. [7] Diesel Recip. > 600 hp.-Marine Tier 1, for NOx: 45.0 x N^(-0.20) g/kW-hr, where N is maximum/rated engine rpm from 130-1999. Vessel (Crew) maximum rpm is 1,800 per main
engine. Vessel (Work) main engines maximum rpm are 1000 rpm, and generators and SDT are 1800 rpm. [2] Diesel Recip. < 600 hp.-EPA Tier 1: PM, NOx, and CO emission factors for EPA Tier 1 diesel engines on certain wireline and cement unit engines.

[3] Diesel Recip. < 600 hp.-EPA Tier 2: PM, NOx, and CO emission factors for EPA Tier 2 diesel engines on certain wireline and cement unit engines.

[4] Diesel Recip. < 600 hp.-EPA Tier 3: PM, NOx, and CO emission factors for EPA Tier 3 diesel engines on certain wireline and cement unit engines.

FORM BOEM-139 (October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used). Page 2 of 8COMPANYAREABLOCK LEASE PLATFORM WELLCONTACTPHONEREMARKSBHP Billiton Pet. (GOM) InAtwater Valley574 OCS-G 08035 NA SS003Kathy Camp713.201.9627Drill / complete Well SS003 with DD1 / commence productionOPERATIONSEQUIPMENTRATING MAX. FUELACT. FUEL RUN TIMEMAXIMUM POUNDS PER HOURESTIMATED TONSDiesel EnginesHP GAL/HRGAL/DNat. Gas Engines HP SCF/HRSCF/DBurners MMBTU/HR SCF/HRSCF/D HR/D DAYS PM SOx NOxVOC CO CO2 PM SOx NOxVOC CO CO2DP SemiSEMI-SUBMERSIBLE[1]46323 2237.40 18114.00 24 125 32.97 0.56 1046.97 36.48 169.57 53076.38 16.68 0.28 529.77 18.46 85.80 26856.65DD1PRIME MOVER>600hpdiesel[2] [3]40768 1969.09 47258.2728.76 0.49 942.35 29.66 132.71 46711.61 0.00 0.00 0.00 0.00 0.00 0.00Emergency Generator>600hp diesel 2145 103.60 2486.48 1.51 0.03 52.02 1.56 11.35 2457.68 0.00 0.00 0.00 0.00 0.00 0.00EMERGENCY EQUIP<600hp diesel 350 16.91 405.72 0.77 0.00 10.80 0.86 2.34 401.02 0.00 0.00 0.00 0.00 0.00 0.00WIRELINE <600hpdiesel-POSU-CA PU Eng.[4]300 14.49 347.760.10 0.00 1.97 0.74 1.73 343.73 0.00 0.00 0.00 0.00 0.00 0.00WIRELINE <600hpdiesel-POSU-CA PU Eng.[5]300 14.49 347.760.10 0.00 1.97 0.74 1.73 343.73 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING <600hpdiesel-Batch Mixer[5]250 12.08 289.800.08 0.00 2.73 0.62 1.44 286.44 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING <600hpdiesel(Nitrogenpump)[6]490 23.67 568.010.44 0.01 7.41 1.05 9.18 561.43 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING >600hpdiesel[7]860 41.54 996.910.61 0.01 13.86 0.63 4.55 985.36 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING >600hpdiesel[7]860 41.54 996.910.61 0.01 13.86 0.63 4.55 985.36 0.00 0.00 0.00 0.00 0.00 0.00CrewVESSELS≥37kw diesel(crew)(main-4)[8]9000 434.70 10432.80 24 125 2.96 0.11 106.53 6.55 47.62 10311.95 4.44 0.16 159.80 9.82 71.43 15467.93VESSELS≥37kw diesel(crew)(gens-3)[8]1083 52.31 1255.41 24 125 0.36 0.01 12.82 2.67 8.90 1240.87 0.53 0.02 19.23 4.01 13.35 1861.31Work/SupplyVESSELS>600hp diesel(work) (main-2)[9]13196 637.37 15296.80 24 125 9.31 0.16 245.22 9.60 69.82 15119.62 13.96 0.24 367.84 14.40 104.73 22679.422 vesselsVESSELS>600hp diesel(work) (gen.-2)[9]4881 235.76 5658.33 24 125 3.44 0.06 80.65 3.55 25.83 5592.79 5.17 0.09 120.97 5.33 38.74 8389.19VESSELS>600hp diesel(work) (SDT)[9]2200 106.26 2550.24 24 125 1.55 0.03 36.35 1.60 11.64 2520.70 2.33 0.04 54.52 2.40 17.46 3781.05VESSELS<600hp diesel(work) (E-Generator)502 24.22 581.38 24 125 1.11 0.01 15.48 1.24 3.35 574.64 1.66 0.01 23.22 1.86 5.03 861.97INSTALLATION INSTALLATION Vessel diesel47000 2270.1 54482.40 24 10 0.00 0.00 1456.87 0.00 205.16 0.00 0.00 0.00 174.82 0.00 24.62 0.00jumper / flfowline INSTALLATION Vessel diesel (E-Generator)00 0.000.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00umbilicalSUPPORT VESSEL diesel17000 821.1 19706.40 24 10 0.00 0.00 526.95 0.00 74.21 0.00 0.00 0.00 63.23 0.00 8.90 0.00VESSELS>600hp diesel(crew)00 0.000.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(supply)12000 579.6 13910.40 24 10 0.00 0.00 371.97 0.00 52.38 0.00 0.00 0.00 44.64 0.00 6.29 0.002014YEAR TOTAL (ANNUAL)138.29 2.42 6789.85 153.47 1240.19 228592.05 44.77 0.85 1558.04 56.28 376.36 79897.51EXEMPTIONCALCULATIONDISTANCE FROM LAND IN MILES3796.20 3796.20 3796.20 3796.20 79937.18114[9] Diesel Recip. > 600 hp.-EPA Marine Tier 1: VESSELS: EPA Marine Engine Tier 1 for NOx: 45.0 x N^(-0.20) g/kW-hr, where N is maximum/rated engine rpm. Vessel (Crew) maximum rpm is 1,800 per main engine. Vessel (Work) main engines maximum rpm are 1000 rpm, and generators and SDT are1800 rpm.[1] SEMI-SUBMERSIBLE: TOI's DD1's highest average daily fuel usage in any six (6) month period in the prior two (2) years was for the period June 1, 2011 through November 30, 2011 (12,076 gallons/day). Actual fuel usage is conservatively estimated at 150% of this average.[8] Diesel Recip.≥37kw -Marine Tier 2: VESSELS: EPA Marine Engine Tier 2 for marine engines maunfactured after 2004 with a per cylinder displacement of 1.2 L - >5.0 L.[2] PRIME MOVER >600hp diesel-DD1: TOI's DD-1 maximum output per main engine is 4828 hp/3500 kW with normal operation involves operating four (4) of eight (8) main engines. These calculations conservatively assume operating 8 of 8 engines.[3] PRIME MOVER >600 hp. diesel-DD1: For all pollutants except NOx and CO, the maximum hourly emissions (lbs/hr) are calculated based on the appropriate AP-42 and EPA emission factor and the total engine rating of 4828 HP (mechanical), as the AP-42 and EPA emission factors are based on brakeHP. COMM Engineering testing of TOI's Development Driller 1 (DD-1) eight (8) main engines for NOx and CO was conducted May 2010. The NOx & CO emission factors conservatively utilized the maximum NOx and CO emission rates of the tests.[4] Diesel Recip. < 600 hp.-EPA Tier 3: PM, NOx, and CO emission factors for EPA Tier 3 diesel engines on certain wireline and cement unit engines.[5] Diesel Recip. < 600 hp.-EPA Tier 2: PM, NOx, and CO emission factors for EPA Tier 2 diesel engines on certain wireline and cement unit engines.[6] Diesel Recip. < 600 hp.-EPA Tier 1: PM, NOx, VOC and CO emission factors for EPA Tier 1 diesel engines on certain cement unit engines.[7] Diesel Recip. > 600 hp.-IMO Tier 1 (=> 2000 rpm): NOx emission factors for IMO Tier 1 diesel engines on certain cement unit engines with rated engine rpm is equal to or greater than 2000.FORM BOEM-139(October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used).Page 3 of 8SUMMARYCOMPANY AREABLOCKLEASEPLATFORM WELLBHP Billiton Pet Atwater Valley 574OCS-G 08035 NASS003EmittedSubstanceYearPMSOxNOxVOCCO2014 44.770.851558.0456.28376.36Allowable3796.20 3796.20 3796.20 3796.20 79937.18FORM BOEM-139(October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used).Page 8 of 8

### Page 1 of 14 SPILL RESPONSE DISCUSSION

For the purpose of NEPA and Coastal Zone Mana gement Act analysis, the largest spill volume originating from the proposed activity would be a well bl owout during drilling operations, estimated to be 101,730 barrels of crude oil with an API gravity of 22.9°.

Land Segment and Resource Identification

Trajectories of a spill and the probability of it impacting a land segment have been projected utilizing information in the BS EE Oil Spill Risk Analysis Model (OSRAM) for the Central and

Western Gulf of Mexico available on the BSEE website. The results are shown in Figure 1. The BSEE OSRAM identifies a 3% probability of impact to the shorelines of Plaquemines Parish, Louisiana within 30 days. Plaquemines Parish includes Barataria Bay, the Mississippi River Delta, Breton Sound and the affiliated islands and bays. This region is an extremely sensitive habitat and serves as a migratory, breeding, feedi ng and nursery habitat for numerous species of wildlife. Beaches in this area vary in grain particle size and can be classified as fine sand, shell or perched shell beaches. Sandy and muddy tidal flats are also abundant.

Response

BHP Billiton Petroleum (GOM) Inc. will make ev ery effort to respond to the Worst Case Discharge as effectively as practicable. A desc ription of the response eq uipment under contract

to contain and recover the Wors t Case Discharge is shown in Figure 2.

Using the estimated chemical and physical charact eristics of crude oil, an ADIOS weathering model was run on a similar product from the ADIO S oil database. The results indicate 12% or approximately 12,208 barrels of crude oil would be evaporated/dispersed w ithin 24 hours, with approximately 89,522 barrels remaining.

Spill Response AT 574, Well E001 Barrels of Oil

WCD Volume 101,730

Less 12% natural evaporation/dispersion 12,208

Remaining volume 89,522



### Figure 2 outlines equipment, personnel, materials and support vessels as well as temporary storage equipment available to respond to a spill of approximately 89,522 barrels. The volume accounts for the amount remaining after evaporatio n/dispersion at 24 hours. The list estimates individual times needed for proc urement, load out, travel time to the site and deployment. Figure

2 also indicates how operations will be supported.

BHP Billiton Petroleum (GOM) Inc.’s Oil Spill Response Plan includes alternative response technologies such as dispersants and in-situ burn. Strategies will be decided by Unified Command based on the size of the spill, weather and potential impacts. If aerial dispersants are utilized, 8 sorties (9,600 gallons) from two of the DC-3 aircrafts and 4 sorties (8,000 gallons)

### Page 2 of 14 from the Basler aircraft would provide a dail y dispersant capability of 7,540 barrels. If the conditions are favorable for in-situ burning, the proper approvals have been obtained and the proper planning is in place, in-situ burning of oil may be attempted. Slick containment boom would be immediately called out and on-scene as soon as possible. Offshore response strategies may include attempting to skim utilizing the HOSS Barge, nine Fast Response Units (FRUs), and six sets of Koseq skimming arms, with a total derated skimming capacity of 188,233 barrels. Temporary storage associated with skimming equipment equals 17,700 barrels. If additional storage is needed, a 25,000 barrel storage barge, three 20,000 barrel storage barges, and an 86,948 barrel storage barge may be mobilized and cen trally located to provide temporary storage allowing the skimmers to stay in the ar ea of operations as much as possible. Safety is first priority. Air monitoring will be accomplished and operations deemed safe prior to any containment/skimming attempts.

If the spill went unabated, shoreline impact in Plaquemines Parish, Louisiana would depend upon existing environmental conditions. Shorelin e protection would include the use of CGA’s

near shore and shallow water skimmers with a totaled derated sk imming capacity of 86,570 barrels. Temporary storage asso ciated with skimming equipm ent equals 1,292 barrels. If additional storage is needed, two 23,000 barrel storage barg es and one 47,000 barrel storage barge may be mobilized and centrally located to provide temporary storage allowing the skimmers to stay in the area of operations as much as possibl e. Onshore response may include the deployment of shoreline boom on beach areas, or protection and sorbent boom on vegetated areas. A Master Service Agreement with ES&H will ensure access to 140,000 feet of 18” shoreline protection boom. Figure 2 outlines individual times needed for procurement, load out, travel time to the site and deployment. Stra tegies would be based upon surveillance and real time trajectories that depict areas of potentia l impact given actual sea and weather conditions. The State of Louisiana Initial Oil Spill Respon se Plan for Plaquemines Parish and Unified

Command would be consulted to ensure that environmental and special economic resources would be correctly identified and prioritized to ensure optimal protection. Shoreline protection strategies depict the protection response modes applicable for oil spill clean-up operations. The

State of Louisiana Initial O il Spill Response Plan provides detailed shoreline protection strategies for this area, and it describes necessary action to k eep the oil spill from entering Louisiana’s coastal wetlands, base d on the assumption that removal of the released oil will be much easier and less damaging to fragile coastal ecosystems if done in the open waters of the Gulf of Mexico. Supervisory personnel have the option to modify the deployment and operation of equipment allowing a more effective response to site-specific circ umstances. BHP Billiton Petroleum (GOM) Inc.’s contract Spill Management Team holds a copy of the State of Louisiana Initial Oil Spill Response Plan.

Based on the anticipated worst case discharge sc enario, BHP Billiton Petroleum (GOM) Inc. can be onsite with contracted oil spill recovery equi pment with adequate response capacity to contain and recover surface hydrocarbons, and prevent land impact, to the maximum extent practicable, within an estimated 62 hours (based on the equi pment’s Effective Daily Recovery Capacity (EDRC)).

### Page 3 of 14 Initial Response Considerations Actual actions taken during an oil spill response will be based on many factors which include but

are not limited to:

• Weather

• Equipment and materials availability

• Ocean currents and tides

• Location of the spill

• Product spilled

• Amount spilled

• Environmental risk assessments

• Trajectory and product analysis

• Well status, i.e., shut in or continual release

BHP Billiton Petroleum (GOM) Inc. will take action to provide a safe, aggressive response to contain and recover as much of the spilled oil as quickly as it is safe to do so. In an effort to protect the environment, response actions will be designed to provide an “in-depth” protection strategy meant to recover as much oil as possible as far from environmentally sensitive areas as possible. Safety will take precedence over all other considerations during these operations.

Coordination of response assets will be supe rvised by the designation of a SIMOPS group as necessary for close quarter vessel response activitie s. Most often, this gr oup will be used during source control events that require a significant nu mber of large vessels operating independently, but in coordination to complete a common objec tive, in a small area and in close coordination and support of each other. This group must also monitor the subsurface activ ities of each vessel (ROV, dispersant application, well control sup port, etc.). The SIMOPS group leader reports to

the Source Control Section Chief.

In addition, these activities will be monitored by the spill mana gement team (SMT) and Unified

Command via a structured Common Operating Picture (COP) esta blished to track resource and

slick movement in real time.

Upon notification of a spill, the following actions will be taken:

• Information will be confirmed

• An assessment will be made and initial objectives set

• OSROs and appropriate agen cies will be notified

• ICS 201, Initial Report Form will be completed

• Initial Safety plan will be written and published

• Unified Command will be established

o Overall safety plan developed to reflect the operational situa tion and coordinated objectives

o Areas of responsibility esta blished for Source Control a nd each surface operational

site

o On-site command and control established

### Page 4 of 14 Decanting Strategy Recovered oil and water mixtures will typically se parate into distinct phases when left in a quiescent state. When separati on occurs, the relatively clean water phase can be siphoned or decanted back to the recovery point with minima l, if any, impact. Decanting therefore increases the effective on-site oil storage capacity a nd equipment operating time. FOSC/SOSC approval will be requested prior to decanting operations. This practice is routinely used for oil spill

recovery.

Offshore Response Actions

Equipment Deployment

Surveillance

• Surveillance Aircraft will be deployed within two hours of Qu alified Individual (QI) notification, or at first light

• Provide trained observer to pr ovide on site status reports

• Provide command and control platfo rm at the site if needed

• Continual surveillance of oil movement by remote sensing systems, aerial photography

and visual confirmation

• Continual monitoring of vessel assets using vessel monitoring systems

Dispersant application assets

• Put Airborne Support Inc. (ASI) on standby

• With the Federal On-Scene Coordinator (FOSC), conduct analysis to determine appropriateness of dispersant application

• Gain FOSC approval for use of dispersants on the surface

• Deploy aircraft in accordance with a plan developed for the actual situation

• Coordinate movement of dispersants, ai rcraft, and support equipment and personnel

• Confirm dispersant availability fo r current and long range operations

• Start ordering dispersa nt stocks required for expected operations

Containment boom ,

• Call out early and expedite deployment to be on scene ASAP

• Ensure boom handling and mooring equipment is deployed with boom

• Provide continuing reports to vessels to expedite their arrival at sites that will provide for

their most effective containment

• Use Vessels of Opportunity (VOO) to deploy and maintain boom

Dedicated off-shore skimming systems

General

• Deployed to the highest concentration of oil

• Assets deployed at safe distance from aer ial dispersant and in-situ burn operations

### Page 5 of 14 CGA HOSS Barge

• Use in areas with heaviest oil concentrations

• Consider for use in areas of known debris (seaweed, and other floating materials)

CGA FRUs

• To the area of the thickest oil

• Use as far off-shore as allowed

• VOOs 140’ – 180’ in length

• VOOs with minimum of 18’ x 38’ or 23’ x 50’ of optimum deck space

• VOOs in shallow water should have a dr aft of <10 feet when fully loaded

Storage Vessels

• Establish availability of CGA contracted assets

• Early call out (to allow for tug boa t acquisition and deployment speeds)

• Phase mobilization to allow storage vessels to arrive at the same time as skimming

systems

• Position as closely as possible to ski mming assets to minimize offloading time

Vessels of Opportunity (VOO)

• Use BHP Billiton Petroleum (GOM) Inc.’s contracted resources as applicable

• Industry vessels are usually best for deployment of Vessel of Opportunity Skimming Systems (VOSS)

• Acquire additional resources as needed

• Consider use of local assets, i.e. fishing and pleasure craft

• Expect mission specific and sa fety training to be required

• Plan with the US Coast Guard for vessel inspections

In-situ Burn assets

• Determine appropriateness of in-situ burn ope ration in coordination with the FOSC and affected State On-Scene Coordinator (SOSC)

• Determine availability of fire boom and selected ignition systems

• Start ordering fire boom stocks required for expected operations

• Contact boom manufacturer to provide training if required

• Determine assets to perform on water operation

• Build operations into safety plan

• Conduct operations in accordance with an approved plan

Adverse Weather Operations:

In adverse weather, when seas are > 3 feet, the use of larger recovery and storage vessels, oleophilic skimmers, and large offshore boom will be maximized. Safety will be the overriding factor in all operations and will cease at the order of the Unified Command, vessel captain, or in an emergency, ”stop work” may be directed by any crew member.

### Page 6 of 14 Near Shore Response Actions

Timing

• Place near shore assets on standby and depl oy in accordance with planning based on the actual situation, actual traj ectories and oil budgets

• VOO identification and training in advance of spill nearing shoreline if possible

• Outfitting of VOOs for specific missions

• Deployment of assets based on actual movement of oil

Considerations

• Water depth, vessel draft

• Shoreline gradient

• State of the oil

• Use of VOOs

• Distance of surf zone from shoreline

Equipment Deployment

Surveillance

• Provide trained observer to direct skimming operations

• Continual surveillance of oil movement by remote sensing systems, aerial photography

and visual confirmation

• Continual monitoring of vessel assets

Dispersant Use

• Generally will not be approved within 3 miles of shore or with less than 10 meters of water depth

• Approval would be at Regional Re sponse Team level (Region 6)

Vessel Deployment Dedicated Near Shore skimming systems

• Fast Response Vessels (FRV)

• Egmopol and Marco Shallow Water Skimmer (SWS)

• Operate with aerial spotter directi ng systems to observed oil slicks

VOO

• Use BHP Billiton Petroleum (GOM) Inc.’s contracted resources as applicable

• Industry vessels are usually best for deployment of Vessel of Opportunity Skimming Systems (VOSS)

• Acquire additional resources as needed

• Consider use of local assets, i.e. fishing and pleasure craft

• Expect mission specific and sa fety training to be required

• Plan with the US Coast Guard for vessel inspections

• Operate with aerial spotter d irecting systems to oil patches

### Page 7 of 14 Shoreline Protection Operations

Response Planning Considerations

• Environmental risk assessments (ERA) to determine priorities for area protection

• Time to acquire personnel and eq uipment and their availability

• Previous contingency planning contained in the appropriate Area Contingency Plan, and currently for Louisiana, The State of Loui siana Initial Oil Spill Response Plan, Deep Water Horizon, dated 2 May 2010

Actions

Placement of boom

• Position boom in accordance with the ERA based on the actual situation or the appropriate ACP

• Assess timing of booming operations to ensure it is where it needs to be at time of impact. Consider:

o Trajectories

o Weather forecast

o Oil Impact forecast

o Verified spill movement

o Boom, manpower and vessel (shallow draft) availability

o Near shore boom and support material, (stakes, anchors, line)

Beach Preparation

Considerations and Actions

• Use of a 10 mile go/no go line to determine timing of beach cleaning

• Shoreline Cleanup and Assessment Team Reports and recommendations

• Determination of Archeological site s and gaining authority to enter

• Monitoring of tide tables and weather to determine extent of high tides

• Pre cleaning of beaches by moving waste above high tide lines to minimize waste

• Staging of equipment and housing of respons e personnel as close to the job site as possible to maximize on-site work time

• Boom tending, repair, replacement and security (u se of local assets may be advantageous)

• Constant awareness of weather and oil moveme nt for resource redeployment as necessary

• In-situ burn may be considered when marshes have been impacted

• Passive clean up of marshes should be consider ed and appropriate stoc ks of sorbent boom and/or sweep obtained

• Earthen berms and shoreline protection boom may be considered to protect sensitive

inland areas

### Page 8 of 14 Decanting Strategy Recovered oil and water mixtures will typically se parate into distinct phases when left in a quiescent state. When separati on occurs, the relatively clean water phase can be siphoned or decanted back to the recovery point with minima l, if any, impact. Decan ting therefore increases the effective on-site oil storage capacity a nd equipment operating time. FOSC/SOSC approval will be requested prior to decanting operations. This practice is routinely used for oil spill

recovery.

CGA Equipment Limitations The capability for any spill response equipment, whether a dedicated or portable system, to operate in differing weather conditions will be directly in rela tion to the capabilities of the vessel the system in placed on. Most importantly, however, the decision to operate will be based on the judgment of the Unified Command a nd/or the Captain of the vessel, who will ultimately have the final say in terminating operations. Skimming equipment listed below may have operational limits which exceed those safety thresholds. As was seen in the Deepwater Horizon (DWH) oil spill response, vessel skimming opera tions ceased when seas reache d 5-6 feet and vessels were often recalled to port when those conditions were exceeded. Systems below are some of the most up-to-date systems available and were employed during the DWH spill.

Boom 3 foot seas, 20 knot winds Dispersants Winds more than 25 knots Visibility less than 3 nautical miles Ceiling less than 1,000 feet.

FRU 8 foot seas HOSS Barge/OSRB 8 foot seas Koseq Arms 8 foot seas

OSRV 4 foot seas

### Page 9 of 14 Environmental Conditions in the GOM Louisiana is situated between the easterly and westerly wind belts, and therefore, experiences westerly winds during the wint er and easterly winds in the summer. Average wind speed is generally 14-15 mph along the coast. Wave he ights average 4 and 5 feet. However, during hurricane season, Louisiana has recorded wave heights ranging from 40 to 50 feet high and winds reaching speeds of 100 mph. Because much of southern Louisiana lies below sea level, flooding is prominent.

Surface water temperature ranges between 70 and 80  ̊ F during the summer months. During the winter, the average temperatur e will range from 50 and 60  ̊ F.

The Atlantic and Gulf of Mexico hurricane seas on is officially from 1 June to 30 November. 97% of all tropical activity occurs within this window. The Atlant ic basin shows a very peaked season from August through October, with 78% of the tropical storm days, 87% of the minor (Saffir-Simpson Scale categories 1 and 2) hurricane days, and 96% of the major (Saffir-Simpson categories 3, 4 and 5) hurricane days occurri ng then. Maximum activity is in early to mid September. Once in a few years there may be a hurri cane occurring "out of season" - primarily in May or December. Globally, September is the mo st active month and May is the least active

month.

### Page 10 of 14 FIGURE 1

TRAJECTORY BY LAND SEGMENT

Trajectory of a spill and the probability of it impacting a land segment have been projected utilizing BHP Billiton Petroleum (GOM) Inc.’s WCD and information in the BSEE Oil Spill Risk Analysis Model (OSRAM) for th e Central and Western Gulf of Mexico available on the BSEE website using 30 day im pact. The results are tabulated below.

Area/Block OCS-G Launch

Area Land Segment and/or

Resource Conditional Probability (%) within 30 days

AT 574, Well E001

114 miles from shore G08035 C62 Jefferson, TX
Cameron, LA Vermilion, LA Terrebonne, LA Lafourche, LA Plaquemines, LA 1

2

1

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3Page 11 of 14WCD Scenario– BASED ON WELL BLOWOUT DURING DRILLING OPERATIONS(114 miles from shore)89,522 bbls of crude oil (Volume considering natural weathering)API Gravity 22.9°FIGURE 2 – Equipment Response Time to AT 574, Well E001Dispersants/SurveillanceDispersant/SurveillanceDispersantCapacity (gal)StorageCapacityPersons Req.FromHrs toProcureHrs toLoadoutTravel tositeTotal HrsCGABasler 67T2000NA2Houma1 1 0.82.8ASIDC 31200NA2Houma1 1 13DC 31200NA2Houma1 1 13Aero CommanderNANA2Houma1 1 0.82.8Offshore ResponseOffshore Equipment NoStagingEDRCStorageCapacityVOOPersonsRequiredFromHrs toProcureHrs toLoadoutHrs toGOMTravel toSpill SiteHrs toDeployTotalHrsT&T Marine (available through contract with CGA)Koseq Skimming Arms (3) 53487 6000 3 Utility 18 Leeville 24 24 210 2 62Koseq Skimming Arms (1) 17829 2000 1 Utility 6 Fourchon 24 24 110 2 61Koseq Skimming Arms (2) 35658 4000 2 Utility 12 Venice 24 24 29.2 2 61.2CGAHOSS Barge43000 4000 3 Tugs 5Harvey 7 0 5 13.8 1 26.8Boom Barge (CGA-300)42” Auto Boom (25000’)NA NA1 Tug50 Crew4 (Barge)2 (Per Crew)Leeville 4 0 6 17.1 1.5 28.6Recovered Oil Storage NoStagingEDRCStorageCapacityVOOPersonsRequiredFromHrs toProcureHrs toLoadoutHrs toGOMTravel toSpill SiteHrs toDeployTotalHrsK-Sea Operating (available through contract with CGA)DBL 81 1132231NA 86948 1 Tug 6Venice 4 12 2 13.75 1 32.75Enterprise Marine Services LLC (available through contract with CGA)CTCo 2603NA 25000 1 Tug 6Amelia 4 12 420 1 41CTCo 2604NA 20000 1 Tug 6Amelia 4 12 420 1 41CTCo 2605NA 20000 1 Tug 6Amelia 4 12 420 1 41CTCo 2606NA 20000 1 Tug 6Amelia 4 12 420 1 41Page 12 of 14Staging Area: VeniceOffshore Equipment WithStagingEDRCStorageCapacityVOOPersonsReq.FromHrs toProcureHrs toLoadoutTravel toStagingTravel to SiteHrs toDeployTotalHrsCGAFRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Galveston 1 2 89.2 1 21.2FRU (1) + 100 bbl Tank (1) 4251 100 1 Utility 6Harvey 1 2 1.75 9.2 1 14.9FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Ingleside 1 2 11 9.2 1 24.2FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Lake Charles 1 2 5.5 9.2 1 18.7FRU (2) + 100 bbl Tank (2) 8502 400 2 Utility 12 Leeville 1 2 3.5 9.2 1 16.7FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Morgan City 1 2 3.25 9.2 1 16.4FRU (2) + 100 bbl Tank (4) 8502 400 2 Utility 12 Venice 1 2 09.2 1 13.2Hydro-Fire BoomNA NA 8 Utility40 Harvey 1 4 1.75 9.2 6 21.9Page 13 of 14Nearshore ResponseNearshore Equipment NoStagingEDRCStorageCapacityVOOPersonsRequiredFromHrs toProcureHrs toLoadoutHrs toGOMTravel toSpill SiteHrs toDeployTotalHrsCGA46’ FRV5000 65 NA 4Leeville 1 0 220 546’ FRV5000 65 NA 4Venice 1 0 120 4Trinity SWS21500 249 NA 4Leeville 1 2 220 7Trinity SWS21500 249 NA 4 Morgan City 1 2 24.8 0 9.8Trinity SWS21500 249 NA 4Venice 1 2 220 7Enterprise Marine Services LLC (available through contract with CGA)CTCo 2607NA 23000 1 Tug 6Amelia 4 12 415 1 36CTCo 2608NA 23000 1 Tug 6Amelia 4 12 415 1 36CTCo 5001NA 47000 1 Tug 6Amelia 4 12 415 1 36Staging Area: VeniceNearshore and Inland SkimmersWith StagingEDRCStorageCapacityVOOPersonsReq.FromHrs toProcureHrs toLoadoutTravel toStagingTravel toDeploymentHrs toDeployTotalHrsCGASWS Egmopol3000 100 NA 3 Morgan City 1 2 3.25 2 0 8.25SWS Marco3588 34 NA 3 Leeville 1 2 3.52 0 8.5SWS Marco3588 34 NA 3 Venice 1 2 02 0 5Rope Mop772 0 3 Harvey 1 2 82 0 13Foilex Skim Package (TDS 150) 891 45 NA 3 Harvey 1 2 1.75 2 0 114 Drum Skimmer (Magnum 100) 686 100 1 Crew 3 Harvey 1 2 1.75 2 0 112 Drum Skimmer (TDS 118)240 100 1 Crew 3 Lake Charles 1 2 5.52 0 8Page 14 of 14Shoreline ProtectionStaging Area: VeniceShoreline ProtectionBoomVOOPersonsReq.Storage/WarehouseLocationHrs toProcureHrs toLoadoutTravel toStagingTravel toDeploymentHrs toDeployTotal HrsES&H (available through MSA)50,000’ 18” Boom15 Lake Charles, LA .5 .5 5.521523.520,000’ 18” Boom10 Belle Chasse, LA .5 .52261115,000’ 18” Boom8Mobile, AL .5 .5 4.252411.255,000’ 18” Boom4 Dallas Ft. Worth, TX .5 .5 10.252215.2550,000’ 18” Boom15Houma, LA .5 .5321521Beach BoomEDRCStorageCapacityVOOPersonsReq.FromHrs toProcureHrs toLoadoutTravel toStagingTravel toDeploymentHrs toDeployTotalHrsCGABeach Boom (2000’)NA NA NA 6 Galveston 1 2 81 2 14Beach Boom (1000’)NA NA NA 4 Ingleside 1 2 111 2 17Beach Boom (2000’)NA NA NA 6 Pascagoula 1 2 41 2 10Wildlife ResponseEDRCStorageCapacityVOOPersonsReq.FromHrs toProcureHrs toLoadoutTravel toStagingTravel toDeploymentHrs toDeployTotalHrsCGAWildlife Support TrailerNA NA NA 2 Houma 1 2 31 2 9Bird Scare Guns (24)NA NA NA 2 Belle Chasse 1 2 1.51 2 7.5Bird Scare Guns (12)NA NA NA 2 Galveston 1 2 81 2 14Bird Scare Guns (24)NA NA NA 2 Houma 1 2 31 2 9Bird Scare Guns (12)NA NA NA 2 Ingleside 1 2 111 2 17Bird Scare Guns (24)NA NA NA 2 Lake Charles 1 2 5.51 2 11.5Bird Scare Guns (24)NA NA NA 2 Pascagoula 1 2 41 2 10Response AssetTotalOffshore EDRC188,233Offshore Recovered Oil Storage189,648Nearshore / Shallow Water EDRC86,570Nearshore / Shallow Water Recovered Oil Storage 94,292Worst Case DischargeNeptune SS03Discharge rateExpected Discharge RatesInitial60 DayUnits DischargeUnitsDischargeTotal Liquid RateBBL/Day38440Total Liquid RateBBL/Day22400Oil RateSTB/Day19800Oil RateSTB/Day13650Water RateBBL/day18640Water RateBBL/day8750Gas Rate* MMscf/Day17.2Gas Rate* MMscf/Day11.9Cum OilMMSTB-Cum OilMMSTB1.030 Day100 DayUnits DischargeUnitsDischargeTotal Liquid RateBBL/Day29120Total Liquid RateBBL/Day15970Oil RateSTB/Day16390Oil RateSTB/Day10700Water RateBBL/day12730Water RateBBL/day5270Gas Rate* MMscf/Day14.2Gas Rate* MMscf/Day9.3Cum OilMMSTB0.54Cum OilMMSTB1.5