UNITED STATES GOVERNMENT MEMORANDUM

To: Public Information (MS 5030)

Plans Section, Office of Field Operations (MS 5231)

Public Information copy of DOCD

Control # - S-07652

Type - Supplemental Development Operations Coordinations Document

Lease(s) - OCS-G08035 Block - 574 Atwater Valley Area
OCS-G08038 Block - 618 Atwater Valley Area

Operator - BHP Billiton Petroleum (GOM) Inc.

Wells SB03 and SB03R

%14FNJTVCNFSTJCMFBOE%SJMMTIJQ

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.

Chiquita Hill

Plan Coordinator

G08035/AT/574

G08035/AT/574 1555 FNL, 5440 FEL

1589 FNL, 5390 FEL G08038/AT/618

G08038/AT/618 WELL/SB03

WELL/SB03R Botm Lse/Area/Blk Surface Location Surf Lse/Area/Blk Site Type/Name Description -

Rig Type - Subject: From: April 8, 2014

# bhpbiUito n

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.bhpbllliton.co m

Januar y 30

, 201 4

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 IVIanagemen 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 SB00 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-G0 4 (extende d b y NT L 2014-G03

, 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 permittin g tw o (2 ) additiona l wells

, installin g on e (1 ) associate d jumpe r 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 Ma y 1

, 2014

.

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:J C

Enclosure s

## TABLE OF CONTENTS

SECTION 1:

CONTENTS OF PLAN

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

Plan Information Form

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

Ba thymetry Map and Location Plat

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

Safety and Pollution Prevention Features

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

Storag e 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 Prevention 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 Cha racteristics

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

New or Unusual Technology

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

Bonding Information

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

Oil Spill Financial Responsibility (OSFR)

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

Dee pwater Well Control Statement

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

Suspensions of Production

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

Blowout Scenario

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

Chemical Products

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



## SECTION 3:

GEOLOGICAL AND GEOPHYSICAL INFO RMATION

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

Geological Description

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

Structure Contour Maps

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

Interpreted 2

- D or 3

- D Seismic Lines

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

Geological Structure Cross

- Sections

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

Shallow Hazards Report

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

Site Specific Shallow Hazards Assessment

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

High Resolution Seismic Lines

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

### Stra tigraphic Column

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

Time Versus Depth Table

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

Geochemical Information

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

Future G&G Activities

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



## SECTION 4:

HYDROGEN SULFIDE INFORMATION

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

Concentration

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

Classification Request

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

Contingency Plan

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

Modeling Report

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



## SECTION 5:

MINERAL AND RESOURCE CONVERSATION INFORMATION

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

Technology and Reservoir Engineering Practices and Procedures

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

Technology and Recovery Practices and Procedures

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

Reservoir Development

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



## SECTION 6:

BIOLOGICAL, PHYSICAL AND SOCIOECONOMIC INFORMATION

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

Chemosy nthetic Communities Report

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

Topographic Features Map

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

Topographic Features Statement

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

Live Bottom (Pinnacle Trend) Map

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

Live Bottom (Low Relief) Map

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

Potentially Sensitive Biological Features

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

ROV Monitoring Survey Plan

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

Threatened and Endangered Species Information

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

Archaeological Report

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

Air and Water Quality Information

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

Socioeconomic Information

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



## SECTION 7:

WASTE AND DISCHARGE INFORMATION

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

Projected Generated Wastes

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

Projected Ocean Discharges

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

Modeling Report

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

NPDES Permits

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

### Cooling Water Intakes

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



## SECTION 8:

AIR EMISSIONS INFORMATION

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

Screening Checklist

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

Summary Table (s) o f Plan Emissions

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



## SECTION 9:

OIL SPILL INFORMATION

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

Site Specific OSRP

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

Regional or Sub

- Regional OSRP Information

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

Spill Response Sites

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

OSRO Information

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

Worst Case Scenario Determination

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

NTL 2010

- NO6 - WCD Calculations Overview

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

Oil Spill Response Discussion / NEPA Analysis

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

Modeling Report

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



## SECTION 1 0:

ENVIRONMENTAL MONITORING INFORMATION

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

Monitoring Systems

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

Incidental Takes

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

Flower Garden Banks National Marine Sanctuary

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



## SECTION 1 1:

LEASE STIPULATIONS INFORMATION

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



## SECTION 1 2:

ENVIRONMENTAL MITIGATION MEASURES INFORMATION

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

Impacts to Marine & Coastal Environments & Habitats, Biota, and T hreatened & Endangered Species 25

Incidental Takes

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



## SECTION 1 3:

DECOMMISSIONING INFORMATION

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



## SECTION 1 4:

RELATED FACILITIES AND OPERATIONS INFORMATION

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

Related OCS Facilities and Operations

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

Transportation System

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

Produced Liquid Hydrocarbon s Transportation Vessels

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



## SECTION 1 5:

SUPPORT VESSELS AND AIRCRAFT INFORMATION

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

### General

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

Diesel Oil Supply Vessels

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

Drilling Fluids Transportation

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

Solid and Liquid Wastes Transportation

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

Vicinity Map

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



## SECTION 1 6:

ONSHORE SUPPORT FACILIT IES INFORMATION

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

General

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

Support Base Construction or Expansion

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

Support Base Construction or Expansion Timetable

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

Air Emissions

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

Unusual Solid and Liquid Wastes

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

Waste Disposal

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



## SECTION 1 7:

SULPHUR OPERATIONS INFORMATION

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



## SECTION 1 8:

COASTAL ZONE MANAGEMENT ACT (CZMA) INFORMATION

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

Consistency Certification

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

Other Information

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



## SECTION 1 9:

ENVIRONMENTAL IMPACT ANALYSIS (EIA)

......................................................................................... 32

Impact Producing Factors (IPFs) from the Proposed Activities

................................................................ 32

Analysis

................................................................................................ ..................................................... 33

Environmental Hazards

............................................................................................................................ 40

Alternatives

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

Mitigation Measures

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

Consultation

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

Preparer(s)

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

References

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



## SECTION 20 :

ADMINISTRATIVE INFORMATION

....................................................................................................... 43

Exempted Information Description (Public Information Copies Only)

..................................................... 43

Bibliography

................................................................................................ .............................................. 43

### Plan Attachments

Attachment A Plan Information Form s
Attachment B Well Location Map s Attachment C Bathymetry Map

Attachment D Pay.gov Service Fee

Attachment E Structure Map

Attachment F Cross Section

Attachment G Seismic

Attachment H Solid and Liquid Wastes Transportati on
Attachment I Air Emissions

Attachment J NEPA Spill Response Discussion

Attachment K Subsea Tree Drawing

Attachment L Vicinity Map

Attachment M Worst Case DischargeBHP Billiton Petroleum (GOM) Inc. 1 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

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

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

Lease s OCS - G 08035, 08036 and 08038

Offshore Louisiana



### SECTION 1 **- CONTENTS OF PLAN** 

Under this Suppleme ntal 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 t o produce several subsea

wells

.

BHPB proposes to supplement the DOCD as follows:

• Drill and complete Subsea Well SB 003 to a proposed bottom hole located in Block 574
– the surface will be located adjacent to the existing sled and existing Wells SB001 an d SB002 in

Block 618

• Install one (1) jumper from the proposed SB003 well to the existing inline sled

• Commence production by May 1, 2014

• BHPB is requesting approval for an additional well (to be designated SB003 (Respud)) in the event an issue arises during drilling of the riserless portion of SB003.

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”

SA 001 See Remarks Permanently Abandoned

SB001ST01 02/19/2008 07/21/2008 Producing

SC001ST03 11/30/2007 07/10/2008 Producing

SC002 07/04/2007 07/07/2008 Producing

SC003 08/15/2007 07/08/2008 Producing

SD001 10/10/2007 08/10/2008 Presently being TA’d

SD 001ST01 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 Comple te Date Production Start

Date Status

SC004 05/10/2008 07/17/2008 Producing

Supplemental DOCD
– Plan S

- 7343
– approved August 29, 2009

Well Name Complete Date Production Start

Date Status

SB002 09/16/2009 12/21/2009 ProducingBHP Billiton Petroleum (GOM) Inc. 2 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 Supplemental DOCD – Pl an 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

Supplemental DOCD
– Plan S

- 7614
– in review

Well Name Complete Date Production Start

Date Status

SS003 Not Drilled Yet



### (a) Plan Information Form

An OCS Plan Information Form ( BOEM

- 137) with details of the proposed drilling and completion operations and jumper installation along with BHPB’s tentative schedule leading up to commencement of production is included as Attachment A

.

The proposed well (s) will be drilled with either a DP drill ship (CRL) or a DP semi

- submersible ( Invictus ) using sub surface BOPs . There will be no anchors associated with the operations proposed in this Plan.



### (b) B athymetry 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 existing and proposed surface an d bottomhole locations of

the wells addressed in this Plan.

BHP Billiton proposes to utilize dynamically

- positioned drilling vessels; therefore, there will be no anchors associated with this activity.



### (c) Safety and Pollution Prevention Features

The proposed well s addressed in this Plan will be drilled with the either a DP drillship or a DP semi

submersible using subsurface BOPs

.

Safety features on the MODU will include well control, pollution prevention, welding procedure, and blowout prevention equipment a s described 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 Product ion Plans, and Development Operations Coordination Documents on the OCS

• NTL 2010

- N10 for Statement of Compliance with Applicable Regulations and Evaluation of Information Demonstrating Adequate Spill Response and Well Containment ResourcesBHP Billiton Petroleum (GOM) Inc. 3 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 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 the baseline for these inspections.

BSEE also i nspects the stockpiles of equipment listed in the Operator's approved 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.

Supe rvisory 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

Perm it referenced above. BHPB’s permit number is GMG290184.



### (d) S torage 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) Num ber of

Tanks Total Capacity (bbls) Fluid Gravity (API)

L ube O il 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)

Lube Oil Tank P / S Drillship

– Invi ctus 371; 123; 183; 164 4 842 24

- 26 o

Dirty Oil Tank Drillship

– Invictus 48; 658; 243 3 949 29

- 39 o

Diesel Oil Drillship

– Invictus 14,960; 14,268(2);
1,336; 1,413(2); 1,336;
1,145(2) 9 51,285 35 o

Base Oil Drillship

– Invictus 5,058; 398 2 5,455 33 oBHP Billiton Petroleum (GOM) Inc. 4 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### (e) Service Fees

In accordance with 30 CFR 5 50.125 (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 Deflator for Gross Domestic Product by publication of a document in the Federal Register. If a significant adjustment is needed to arrive 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 §5 50.211 (d)

[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) accompanies 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 overboard discharges into the receiving waters, as outlined

in EPA’s NPDES General Permit GMG290000.

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

BHPB will utilize the best management practices available 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 drilling operations understand the state and federal regulations.

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.



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

In accordance with the provisions of Title 30 CFR 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 the response to a complete loss of well control. BHPB is a member of the Marine Well Containment Company (MWCC). At thi s time, MWCC is the containment response system of choice for BHPB’s exploration project.

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

.BHP Billiton Petroleum (GOM) Inc. 5 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### SECTION 2 **- GENERAL INFORMATION** 

(a) A pplications and Permits

Application / Permit Issuing Agency Status

APD BSEE District To be submitted via eWell

Supplemental DWOP BSEE Region In preparation

Lease Term Pipeline BSEE Region In preparation

Surface Safety Systems BSEE District In preparation

Notice of Intent to Discharge EPA Region 6 In preparation

Surfa ce Commingle BSEE Region In preparation



### (b) D rilling Fluids

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

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

Water

- based (SW, FW, Barite) 28,216 bbls

Oil

- based (diesel, mineral oil) NA

Synthetic

- based (internal olefin, ester, etc) 2,070 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 Sheet s (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 submitted with the Initial DOCD (Control No. N

- 08542).



### (e) N ew or Unusual Technology

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



### (f) B onding Information

The bond requirements for the activities and facilities proposed 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 Bonds”; and National NTL No. 200 8- N07, “Supplemental

Bond Procedures”.BHP Billiton Petroleum (GOM) Inc. 6 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### (g) O il Spill Financial Responsibility (OSFR)

BHPB ( BOEM Operator No. 02010) has demonstrated oil spill financial responsibility for the facilities proposed in this Supplemental Plan 30 CFR Part 253, and NTL No. 200 8- N05, “Guidelines for Oil Spill Financial Responsibility for Covered Facilities”.



### (h) D eepwater 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) B lowout Scenario

The proposed wells will penetrate the objective, hydrocarbon beari ng sands with a 12

- 1/4

- inch drilling assembly below the 13

- 5/8

- inch intermediate casing string. 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 fa il 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 a Master Service Agreement (MSA) with Transocean Ltd. that will allow access to the multiple rigs of opportunity operating in the Gulf of Mexico.

The rigs listed below are currently contracted in GOM:

Rig Name Con tractor Contractor Rated Water Depth (ft) MODU Type Rig Status

Discoverer Americas Transocean 12,000 DP Drill Ship Contracted GOM

C.R. Luigs Transocean 10,000 DP Drill Ship Contracted GOM

Discoverer Deep Seas Transocean 10,000 DP Drill Ship Contracted G OM

Ensco 8500 ENSCO 8,500 DP Semisubmersible Contracted GOM

Ensco 8501 ENSCO 8,500 DP Semisubmersible Contracted GOM

Ensco 8502 ENSCO 8,500 DP Semisubmersible Contracted GOM

West Sirius Seadrill 10,000 DP Semisubmersible Contracted GOM

Maersk Develope r Maersk 10,000 DP Semisubmersible Contracted GOM

Danny Adkins Noble 12,000 DP Semisubmersible Contracted GOMBHP Billiton Petroleum (GOM) Inc. 7 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS-G 08035/08038 

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## PROPRIETARY DAT A REV 3-1-2014BHP Billiton Petroleum (GOM) Inc. 8 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 The BOP stacks on the C.R. Luigs and Invictus 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. P rocedures pertinent to these BOP configurations are well established and familiar to the drillers, tool pushers, and BHPB Drilling Supervisors.



### Likelihood for Surface Intervention to Stop the Blowout
The likelihood for surface intervention 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 Invictus and the C.R. Luigs, to ensure that either rig is capable of latching onto an existing BHPB wellhead.



### Plans for Effective and Early Intervention
Both rigs contracted by BHPB have a Deadman / Autoshear which will function 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 SB 003 surface location. Shallow hazards analysis indicates favorable re lief well locations within this area provided that existing infrastructure, localized areas of steep seafloor slope, and scattered gas anomalies are avoided

.

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

KE Y RIG SPECIFICATIONS FOR RELIEF WELL

RIG NAME INVICTUS C.R. LUIGS

RIG TYPE DSME 12000 TBN #1 MODU rated for 12,000 ft water depth, Dynamically Positioned 5 th 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): 2,800 kips 1,800 kips

Drawworks Power (hp): 9,000 hp 5,000 hp

Mud Pumps Power & Pressure (hp/psi): 4x AKMH Wirth model TPK -7- 1/2 pumps with 2,200 hp, 7,500 psi working 4 x 14 -P- 220 NOV pumps with 2,200 7,475 psi workingBHP Billiton Petroleum (GOM) Inc. 9 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 Mud Pit Volume (bbls): 20,000 bbls 13,267 bbls

Variable Loading (kips): 50,706 kips NA - Drill Ship

Top Drive Power & Torque (hp/ftlbs): Aker MH MDDM

- 1250 -AC- 2M NOV TDS -4

Dry Bulk St orage Capacity (cu. ft): Total Bulk 28,250 cuft Total Bulk 27,000 cuft



### Other Measures Taken
Prior to drilling BHBP will have readily available all of the materials and equipment needed to spud, drill,

case and cement a relief well.

BHPB ha s 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 pl an in the BOEM GOMR.BHP Billiton Petroleum (GOM) Inc. 10 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### SECTION 3 **- GEOLOGICAL AND GEOPHYSICAL INFORMATION** 

In accordance with 43 CFR Part 2 , Appendix B, those items considered proprietary have been omitted from the Public Information copy and have been referenced accordingly.



### (a) G eologi cal Description

**PROPRIETARY DATA**BHP Billiton Petroleum (GOM) Inc. 11 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### (b) S tructure 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.



### (c) I nterpreted 2- D or 3

- D S eismic L ines

Enclosed as Attachment G is a copy of the migrated and annotated deep seismic line within 500 feet o f

W ell SB0 03

.



### (d) G eological S tructure C ross -S ections

An interpreted geological cross

- section showing the location and depth of each existing and proposed well(s) with at least one key horizon and the objective sand labeled is enclosed as Attachment F

.



### (e) S hallow H azards R eport

Numerous shallow hazards reports have been issued to address seafloor and shallow geologic conditions pertinent to drilling wells and installing facilities in the Neptune Field. Following are brief descriptions of the reports pertinent to this Supplemental Plan:

A report titled “Neptune Prospect, Atwater Valley Blocks 574, 575, 618, OCS -G- 8035, OCS -G- 8036,

OCS -G- 8038, Shallow Drilling Hazards Assessment, Supplemental Locations K, L, M, N, and O” wa s prepared by Robert J. Bruce (Consulting Geophysicist) in November 2003. This report was submitted in support of a Supplemental EP (Control No. S

- 6324).

A report titled “Pre

- Feasibility Geohazards Assessment, Neptune Development, Atwater Valley and Gree n Canyon Areas, Gulf of Mexico” was issued by Fugro GeoServices in August 2004. This report delineated seafloor and shallow soil conditions pertinent to field development based primarily on a high

- resolution Autonomous Underwater Vehicle (AUV) geophysical survey acquired by C&C Technologies in February

2004. This report has been submitted with previously reviewed plans and/or permit applications.

A report titled “Multidisciplinary Geologic / Geotechnical Engineering Report, Neptune Field Development,

Gre en Canyon & Atwater Valley Areas, Gulf of Mexico” was issued by Geoscience Earth & Marine Services in January 2006. This report integrated results from piston coring and soil boring geotechnical investigations with the AUV, HR2D, and 3D geophysical surveys to identify potential geohazards and engineering constraints pertinent to the Neptune Field development. This report has been submitted with previously reviewed plans and/or permit applications.

Since the proposed activity will be within 500 f ee t of a p reviously approved surface location, these reports are not attached with this plan. Copies of these reports are available upon request.



### (f) S ite Specific S hallow H azards A ssessment

Since the proposed well is within 500 f ee t of a previously approved surface location (Location K), a shallow hazard assessment is not required at this time. An assessment was previously submitted and reviewed under the Supplemental EP (Control No. S

- 6324) for Locations K, L, M, N and O (see report description above).BHP Billiton Petroleum (GOM) Inc. 12 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### ( g) H igh R esolution S eismic L ines

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 spectral 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.multiclien t.westerngeco.com/NavPDFs/ultra_surveys11.pdf.



### (h) S tratigraphic C olumn

This information is not required for DOCD’s.



### (i) T ime V ersus D epth T ables

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. 13 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### SECTION 4 **- HYDROGEN SULFIDE INFORMATION** 

(a) C oncentration

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



### (b) C lassification R equest

In accordance with Title 30 CFR 250.490(c), BHPB requests the area of operations in Atwater Blocks

574/618 , Lease OCS

- G 08035 and 08038, be classified by the BOEM as an area where the “absence” of Hydrogen sulfide has been confirmed based upon the following:

Correlative Wells for H2S Information:

• Neptune

- 5 (AT574#2; OCS

- G = 8035; API = 608184004400)

• Neptune

- 7 (AT618#2; OCS

- G = 8038; API = 608 184004600)

• SC02 (AT574#3; OCS

- G = 8035; API = 608184006300)



### (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 Repo rt

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. 14 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### SECTION 5 **- MINERAL AND RESOURCE CONVERSATION INFORMATION** 

(a) Technology and Reservoir Engineering Practices and Procedures

Performance of the targeted XXX reservoir is anticipated to be similar to the southern portion of the field,

which has been producing since July 2008. The recovery method will be depletion drive, aided by relatively high rock com pressibility (20
– 22 msips) and potential aquifer support. Various scenarios of gas

and water injection have been modeled with numerical simulation, resulting in small incremental

recoveries that were uneconomic. Continued monitoring of field performance and history matching will be

used to determine if a secondary recovery method should be implemented as part of the overall reservoir management plan, forming part of a future update to the Neptune DOCD.



### (b) Technology and Recovery Practices and Procedure s

Optimum well positioning, trajectory planning and completion design will all be utilized to maximize recovery from primary depletion. Producing wells are connected to a piggable flowline loop that is capable of directing flow in either direction, back to the Neptune TLP in GC

- 613 Block. This provides flexibility for

re

- starts, flow assurance, well start

- up, and system pressure optimization for maximum recovery of

reserves.



### (c) Reservoir Development

**PROPRIETARY DATA**BHP Billiton Petroleum (GOM) Inc. 15 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### SECTION 6 **- BIOLOGICAL, PHYSICAL A**  **ND SOCIOECONOMIC INFORMATION**

(a) C hemosynthetic C ommunities Report

NTL 2009

- G40, effective January 27, 2009, broadened the scope of a chemosynthetic communities report to cover all high

- density deepwater benthic communities (not just high

- density chemosy nthetic communities), changed the definition of deepwater from 400 meters (1,312 feet) to 300 meters (984 feet), increased the separation distance from muds and cuttings discharge locations from 1,500 feet to 2,000 feet and provided for an additional 1,000

- foot buffer area beyond maximum anchor areas.

The seafloor disturbing activities proposed in the Supplemental Plan are in water depths greater than 300 meters (984 feet); therefore, the information described in Attachment A of NTL No. 2009

- G40 is requi red.

As described above, the February 2004 Fugro GeoServices’ report titled “Pre

- Feasibility Geohazards Assessment, Neptune Development, Atwater Valley and Green Canyon Areas, Gulf of Mexico” delineated seafloor features pertinent to field development. According to this Fugro GeoServices’ report and the Shallow Drilling Hazards Assessment conducted by Robert J. Bruce (Consulting Geophysicist) in November 2003 for Location K, there is no evidence for hydrocarbon seepage sites capable of supporting high

- de nsity benthic community development within 2000 feet of the proposed activity. These reports have been submitted with previously reviewed plans and/or permit applications.

There are no features or areas that could support high

- density benthic communities within 2000 feet of the proposed surface location.



### (b) T opographic F eatures M ap

There are no topographic features located on Atwater Valley 574

.



### (c) T opographic F eatures S tatement

Since there are no topographic features located on Atwater Valley 574 the statement for shunting

described in NTL No. 200 9-G 39 “Biologically Sensitive Underwater Features and Areas” is not required.



### (d) L ive B ottom (P innacle T rend ) M ap

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

to the lease.



### (e) L ive B ottom (L ow R elief ) M ap

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 within 61 meters ( 2 00 feet) of potentially sensitive biological features; therefore the map described in NTL No. 2009

- G39 “Biologically Sensitive Underwater

Features and Areas ” is not required.BHP Billiton Petroleum (GOM) Inc. 16 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### (g) ROV M onitoring S urvey P lan

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.



### (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, ecological, 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 conserve threatened and endangered species and their ecosystems. There are more than 1,900 species listed 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 Fisheries Service (NMFS) share responsibility for implementing the ESA. NMFS is responsible for 69 marine species, from whales 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.

B elow 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 Physalus Endangered 12/02/1970
Humpback Whale Megaptera Novaeangliae Endangered 12/02/1970

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

Turtles

Gr een 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 Pectinata Endangered 04/01/2003

Invertebrates

Elkhorn Coral Acropora Palmata Threatened 05/09 /2006 Staghorn Coral Acropora Cervicornis 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 Mexico, which are listed as endangered.

2 Northwest Atlant ic Ocean (NWA) Distinct Population Segment (DPS) was listed as threatened. NMFS and USFWS issued a final rule changing the li sting of loggerhead sea turtles from a single, threatened species to nine DPSs listed as either threatened or endangered in 2012 (7 6 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 offshore operators and contractors.

Further discussions on threatened and endangered species are included in Section 19 (EIA).BHP Billiton Petroleum (GOM) Inc. 17 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### (i) A rchaeological R epor t

The Neptune Field is not located within an area designated to have a high probability for archaeological resources as defined by NTL No. 2005

- G07 and 2011

- JOINT

- G01. However, BHP Billiton is aware of the Bureau of Ocean Energy Management’s (BOEM) March 2011 Pre

- Seabed Disturbance Survey Mitigation and has submitted an archaeological assessment report issued by Geoscience Earth & Marine Services (GEMS) in February 2013 under separate cover (BOEM Survey No. 23658 received Feb. 27, 2013). None of the sonar contacts identified in the Neptune AUV survey area were recommended for archaeological avoidance or investigation.



### (j) Air and Water Quality Information

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



### (k) Socioeconomic Information

The State of Florida is not an affected State for the activities proposed in this plan; therefore this information is not required.BHP Billiton Petroleum (GOM) Inc. 18 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### 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 H (Table 1) . This table includes both operational wastes permitted by the appropriate NPDES permit and any other identifi ed wastes.

BHPB does not plan to treat, store or dispose of any 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 H (Table 1) . This table includes both operational 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 Per mits

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. 19 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS-G 08035/08038 

### 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-G04 (e xtended by NTL 2014-G03), 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 Trinit y Consultants (614.433.0733), 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 SB003. The Neptune TLP and proposed Well is not

collocated activities.

The planned emissions are associated with drilling and completing of the well(s) with either the drillship C.R. Luigs or the DP semi-submersible INVICT US and installing flowline infrastructure.

COMPANY AREA BLOCK LEASE PLATFORM WELL

BHP Billiton Pet. (GOM) Inc. Atwater Valley 574 OCS-G 08035 NA SB003 (CRL)

Year Emitted Substance

PM SOx NOx VOC CO

2014 38.54 0.71 1187.68 47.27 294.22

Allowable 3729.60 3729.60 3729.60 3729.60 78999.49

COMPANY AREA BLOCK LEASE PLATFORM WELL

BHP Billiton Pet. (GOM) Inc. Atwater Valley 574 OCS-G 08035 NA SB003 (INVICTUS)

Year Emitted Substance

PM SOx NOx VOC CO

2014 77.34 1.23 1858.06 95.02 657.55

Allowable 3729.60 3729.60 3729.60 3729.60 78999.49

Detailed spreadsheets are included as Attachment I.

NOTE: There are six (6) diesel-fired main engines on Invictus manufactured by Hyundai Heavy Industries Co., Ltd. Each of these six engines is IMO Tier II certified per regulation 13.4 and rated at 7000 kW power with 720 rpm speed. The International Air Pollution Pr evention Certificates (IAPPCs) for these engines were obtained in Korea. Please find a ttached the supporting engine specification sheets

and IAPPCs for the aforementione d six main engines on the Invictus as requested by BOEM included as

Attachment I-1

.BHP Billiton Petroleum (GOM) Inc. 20 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### SECTION 9 **- OIL SPILL INFORMATION** 

(a) Oil Spill Response Planning

(1) S ite -S pecific OSRP

Lease OCS

- G 08035 is not located in the Eastern Gulf of Mexico therefore a site

- specific OSRP is not required.

(2)(i) R egional or S ub -R egional OSRP I nformation

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 Res ponse Plan filed by BHP Billiton Petroleum (GOM) Inc. (Company No. 02010) that was approved on November 21, 2013.

( ii ) S pill R esponse S ites

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:

Prim ary Response Equipment Location Preplanned Staging Location(s)

Port Fourchon or Houma, LA Port Fourchon, LA

( iii) OSRO I nformation

BHPB’s primary equipment provider is Clean Gulf Associates (CGA). Clean Gulf Associates Services, LLC (CGAS) will provide closest available personnel, as well as a CGAS supervisor to operate the equipment.BHP Billiton Petroleum (GOM) Inc. 21 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 (iv) W orst C ase S cenario Determination

The calculated WCD for this Supplemental DOCD on Lease OCS

- G 08035 do es 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 A T 574 GC 6 5 3 AT 574 Facility Designation 2 Well SH103 ST01 Subsea Well

E001 TLP “A” SB003

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

,ϭϮ͕ρ 4 bbls

ϭϮ͕ρΘϬ bbls Type of Oil(s) (crude oil, condensate, di esel) Crude Crude Crude Crude API Gravity(s) 4 32.1° 22.9o 30o 20- 23 o

*The Regional OSRP calculations and assumptions for 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. 637 3. 3. Take your regional OSRP worst

- case scenario volume from the appropriate section of your regional OSRP. For EP’s, the worst

- case scenario volume is the daily volume possible from an uncontrolled blowout. Determine this volume using the provisions o f 30 CFR 30 CFR 254.47(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 appropriate. 4. Provide API gravity of all oils given under “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 respond, 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 -N 06
– WCD Calculations Overview

BOEM reviewed and calculated a WCD of 101,730 BOPD under Supplemental DOCD Plan No. S

- 7463 in

March 2011. The WCD volume for SB003 is  4  STB oil/day of 20

- 23o API gravity oil and does not

super sede the WCD in BHPB’s approved OSRP. The estimated cumulative discharge volume after 100 days is 

.  MM STB oil. Table 1 shows the expected WCD rates at day 1 and over the time taken to drill

a rel ief 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 SB003 WCD for information purposes in

Attachment M

.BHP Billiton Petroleum (GOM) Inc. 22 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

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

For the purpose of NEPA and Coastal Zone Management Act analysis, the largest spill volume 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 2 2.9 °.

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

.



### (c) Modeling Report

A modeling report for a potential oil or hazardous substance spill is not required for the activities proposed in this plan. In the event BHPB proposes to prepare 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. 23 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### SECTION 10 **- ENVIRONMENTAL MONITORING INFORMATION** 

(a) M onitoring S ystems

BHPB is aware of the requirements of NTL No. 2009

- G02 whereby BOEM established and implemented a program to monitor ocean currents and require operators to share the data for all floating MODU’s and production facilities operating or installed in water depths greater than 400 meters (1,312 feet).

In the event BHPB were to monitor ocean currents during this operation, BHPB will report ocean current data to the National Oceanic and Atmospheric Administration (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 th e 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. 24 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### 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 for Lease OCS

- G 0803 5 /08038 , Atwater Valley Blocks

574/618

.

Atwater Valley Blocks 574/618 is locat ed within the boundaries of the Gulfmex No. 2 lightering zone. BHP Billiton will exercise caution while conducting the proposed activities within this area.BHP Billiton Petroleum (GOM) Inc. 25 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### SECTION 12 **- ENVIRONMENTAL MITIGATION 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 activities proposed in this plan.

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

instruments.BHP Billiton Petroleum (GOM) Inc. 26 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### SECTION 13 **- DECOMMISSIONING INFORMATION** 

This information is not required for plans submitted in the BOEM GOMR.BHP Billiton Petroleum (GOM) Inc. 27 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### SECTION 14 **- RELATED FACILITIES AND OPERATIONS INFORMA**  **TION**

(a) Related OCS Facilities and Operations

A subsea tree will be installed with the rig prior to leaving the location ( Attachment K ) . 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 SB003 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 Flow SI Time

6 AT574 SB003 AT618 Jumper Hub 100’ Oil 2500 BOPD 45s



### (b) Transportation Syst em

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 infrastructure under this Supplemental

Plan

.



### (c) Produced Liquid Hydrocarbons Transportation Vesse ls

There will be no produced liquid Hydrocarbons , including well test fluids, transported by means other than a pipeline for the activities proposed in this plan.BHP Billiton Petroleum (GOM) Inc. 28 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS-G 08035/08038 

### SECTION 15 - SUPPORT VESSELS AND AIRCRAFT INFORMATION

D *HQHUDO

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## PROPRIETARY DAT A REV 3-1-2014BHP Billiton Petroleum (GOM) Inc. 29 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### SECTION 16 **- ONSHORE SUPPORT FACILITIES INFORMATION** 

(a) G eneral

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 facilities therefore a timetable is not required.



### (b) Air Emissions

Information regarding air emissions generated by onshore support facilities is not required to accompany plans submitted in the BOEM GOMR.



### (c) Unusual Solid and Liquid Wastes

Info rmation 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 disposed of during and after our proposed activities are

included in Attachment H (Table 2).BHP Billiton Petroleum (GOM) Inc. 30 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### SECTION 17 **- SULPHUR OPERATIONS INFORMATION** 

BHPB is not proposing to conduct sulphur operations in this plan.BHP Billiton Petroleum (GOM) Inc. 31 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### SECTION 18 **- C OASTAL ZONE MANAGEMENT ACT**  **(CZMA) INFORMATION** 

The States of Tex as, Louisiana , Mississippi, Alabama 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 determine 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 fr om the State of Louisiana is not required for the development activities proposed in this Supplemental Plan

.



### (b) Other Information

State of Louisiana :

T he enforceable policies of the State of Louisiana have been considered and will be complied with.BHP Billiton Petroleum (GOM) Inc. 32 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### 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.

Environ mental

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 l ive 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 sit es (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 Onshor e

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 f or Environmental Impact Analysis Matrix

1. Activities that may affect a marine sanctuary or topographic feature. Specifically, if the well or platform site or any anchors 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 (submarine 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 Topographic 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) Stipulation attached to an

OCS lease.

3. Activities within any Eastern Gulf OCS block where seafloor habitats are protected by the Live Bottom (Low

- Relief) Stipulation 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 diesel 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 note that in a sentence

or two.BHP Billiton Petroleum (GOM) Inc. 33 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 7. All activities that involve seafloor disturbances, including anchor emplacements, in any OCS block designated by the BOEM as having high

probability for the occurrence of shipwrecks or prehistoric sites, including such blocks that will be affected that are adjacent to the lease block in which your planned activity will occur. If the proposed activities are located a sufficient distance from a shipwreck or prehistoric site that no impact would occur, the EIA can note that in a sentence or two.

8. All activities that you determine might 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

Si te

- specific at Atwater Valley Block 574 (bottom hole located in AT 618)



### 1. Designated Topographic Features

The topographic features of the Central 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 disturbances to the seafloor and accidents) that could cause impacts from the proposed development activities in Atwater Valley Blocks 574/618 to topographic

features. The site

- spe cific 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 R egional OSRP.



### 2. P innacle 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, Bureau of Ocean Energy Management

, Regulation and

Enforcement is the agency with jurisdiction over these leases.

The term “live bottom” is used to refer to the biological assemblages attached to hard substrates found interspersed between sand and mud bottoms of the continental 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 effluents, physical disturbances to the seafloor, and accidents) from the proposed development ac tivities in Atwater Valley Blocks 574/618 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. 34 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### 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, Bureau of Ocean Energy Management, Regulation and

Enforcement is the agency with jurisdiction over these leases.

The term “live bottom” is used to refer to the biological assemblages attached to hard substrates found interspersed between sand and mud bottoms of the continental shelf. These assemblages ofte n 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 effluents, physical disturbances to the seafloor, and accidents) from the proposed development activities in Atwater Valley Blocks 574/618 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 their 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 discoveries 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 geographic 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 chemosynthetic metazoans (dependent on hydrocarbon seepage) has been definitively documented (MacDonald, 1992).

There are no documented high

- density chemosynthetic communities in Atwater Valley Blocks 574/618 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

ch emosynthetic communities.

There are no IPF’s (including effluents, physical disturbances to the seafloor, and accidents) from the proposed supplemental development activities in Atwater Valley Blocks 574/618 that could cause impacts to Chemosynthetic Communities (refer to information referenced in Section 6 (a) , Chemosynthetic Communities).



### 5. Water Quality

There are no IPF’s (including effluents, physical disturbances to the seafloor, and accidents) from the proposed supplemental development activities in Atwater Valley Blocks 574/618 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 discharges from the offshor e 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 accordance with a general National Pollutant Discharge Eliminatio n System (NPDES) permit issued by U.S. Environmental Protection Agency (USEPA), operational discharges are not expected to cause significant adverse impacts to water quality.BHP Billiton Petroleum (GOM) Inc. 35 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 With regards to marine trash and debris, effective January 01, 2012, the Bureau of Safety and

Environmental Enforcement issued BSEE NTL No. 2012

- G01 pursuant to 30 CFR 2 50.103 and 30 CFR

5 50.103 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 agencies including the U.S. Coast Guard and the U.S. Environmental Protection Agency, our

emp loyees will ensure that all offshore personnel, including contractors and other support services

related personnel have complete understanding of the requirement that Operators be proactive in avoiding accidental loss of solid waste items on the OCS.

Offs hore accidents, such as blowouts and spills could also occur and have the potential to alter offshore water quality. Given the low frequency of blowouts 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 unlikely 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 marine 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 activities associated with this plan in Atwater Valley

Blocks 574/618 could come from oil spills 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 accidental surface or subsurface oil spill would oc cur 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 dispe rsed 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 proximate 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 cause less than 1 percent decrease in

comm ercial populations or in commercial fishing.

Drilling mud discharges contain chemicals toxic to marine fishes; however, this is only at concentrations 4 or 5 orders of magnitude higher than those found more than a few meters from the discharge point.

O ffshore 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 Mamma ls

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 Atwater Valley Blocks 574 or 618

.BHP Billiton Petroleum (GOM) Inc. 36 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 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 and ingestion of plastic material. Oil spills of any size are estimated to be aperiodic events that may contact cetaceans. Disturbance (e.g., noise) may stress animals, weaken 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). Collisions between cetaceans and ships 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 implement 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 trash and debris, effective January 1, 2012, BSEE issued BSEE NTL No. 2012

- G01 pursuant to 30 CFR 2 50.103 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 environ ment.

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 support services

- related personnel have complete understanding of the requirement that Operators be proactive in avoiding accidental loss of solid waste items on the OCS.



### 8. Sea Turtl es

IPF’s that could impact sea turtles include vessel traffic, noise, trash and debris, and accidental oil spills. Small numbers of turtles could be killed or injured by chance collision 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. Oil

spil l- response planning and the habitat protection requirements 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 persistent physiological or behavioral changes and / or avoidance of affected areas could cause 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 implement 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. 37 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS-G 08035/08038 :LWKUHJDUGVWRPDULQHWUDVKDQGGHEULVHIIHFWLYH-DQXDU\ %6((LVVXHG BSEE NTL No. 2012-

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## PROPRIETARY DAT A REV 3-1-2014BHP Billiton Petroleum (GOM) Inc. 38 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### Vicinity of Offshore Location:

1. Essential Fish Habitat

IPF’s that could impact essential fish habitats as a result of the proposed development 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 accordance with a general National Pollutant Discharge Elimination System (N PDES) 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 operations is small compared with the volume of oil produced . Since 1980, OCS operators have produced about 5.5 BBO of oil, 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 (platforms 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 1 980. An accidental oil spill that may occur 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 proximate 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

a dult 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

Blocks 574/618 include air emissions, accidents and discarded trash and debris.

Emissions of pollutant into the atmosphere from the activities associated with the proposed de velopment operations in this plan are not projected to have significant 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 acc idental oil spill that may occur as a result of the proposed action 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 pr ey.

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 2 50.103 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 wi th 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 support services

- related personnel have complete understanding of the requirement that Operators be proactive in avoiding accidental loss of solid waste items on the OCS.BHP Billiton Petroleum (GOM) Inc. 39 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS-G 08035/08038 

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## PROPRIETARY DAT A REV 3-1-2014BHP Billiton Petroleum (GOM) Inc. 40 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS-G 08035/08038 

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## PROPRIETARY DAT A REV 3-1-2014BHP Billiton Petroleum (GOM) Inc. 41 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 In accordance with requirements set forth in Title 33 CFR 146.140, 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 depression, tropical storm, gale warning, storm warning, hurricane, etc). Major hurricanes (storm having wind speeds in excess of 74 mph) in the Gulf normally form in the southern Gulf or Caribbean Sea. Tropical 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 evaluated on its own merit and the operations modified accordingly. No imp acts are expected on the proposed activities from site

- specific environmental conditions.



### (e ) Alternatives

There are no alternatives other than those required 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

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 201 0- N06 effective June 18, 2010 for Information Requirements for Exploration Plans, Development and Production Plans, and Development Operations Coordination Documents on the OCS

NTL 2009

- G40 effective January 27, 2010 for Deepwater Benthic CommunitiesBHP Billiton Petroleum (GOM) Inc. 42 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 NTL 2009

- G39 effective January 27, 2010 for Biologically

- Sensitive Underwater Features and Areas

NTL 2009

- G27 effective September 9, 2009 for Submitting 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 (extended by NTL 2014

- G03),

BSEE NTL No. 2012

- G01 effective January 1, 2012 for Marine Trash and Debris 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, 207, 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. 43 Atwater Valley Block 574/618 Supplemental DOCD Lease OCS

- G 08035/08038 

### SECTION 20 **- ADMINISTRATIVE INFORMATION** 

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

In accordance with 43 CFR Part 2, Appendix B , the following information is exempt from disclosure and has been omitted from the 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 Information, 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

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 5

###  



# A TTACHMENT A

### 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) SB 03 Previously reviewed under 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) 1254 0 For structures, volume of all storage and pipelines (Bbls) 40 API Gravity of

fluid 20

- 23°

Surface Location Bottom

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

Lease No. G- 0803 8

Area Name AT

Block No. 618

Block Line
Departures (in feet) N/S Departure: 1555 .00 F N L N/S Departure: F____L N/S Departure: F____L N/S Departure: F____L
E/W Departure: 5440 .00 FEL E/W Departure: F____L E/W Departure: F____L E/W Departure: F____L

Lambert X

- Y

coordinates X: 723,200 .00 X:

X:

X:

Y: 9,93 0,125 .00 Y:

Y:

Y:

Latitude / Longitude Latitude: 27o 2 0 ’ 11.499 ”N Latitude:

Latitude:

Latitude:
Longitude: 89o 49’ 31

. 937 ”W Longitude: Longitude: Longitude:
Water Depth (Feet): 6266 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 ( Decemb er 2011 - Supersedes all previous editions of this form which may not be used.) Page 2 of 5

### 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)
SB03 (Respud) Previously reviewed under 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) For structures, volume of all storage and pipelines (Bbls) API Gravity of

fluid

Surface Location Bottom

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

Lease No. G- 08038

Area Name AT

Block No. 618

Block Line
Departures (in feet) N/S Departure: 15 89 .00 FNL N/S Departure: F____L N/S Departure: F____L N/S Departure: F____L
E/W Departure: 5 39 0.00 FEL E/W Departure: F____L E/W Departure: F____L E/W Departure: F____L

Lambert X

- Y

coordinates X: 723,2 5 0.00 X:

X:

X:

Y: 9,930, 091 .00 Y:

Y:

Y:

Latitude / Longitude Latitude: 27o 20’ 11. 17 4”N Latitude:

Latitude:

Latitude:
Longitude: 89o 49’ 31.37 5 ”W Longitude: Longitude: Longitude:
Water Depth (Feet): 6266 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 3 of 5

### 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 Sand 6 Sand 7 Sand 8

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 Mudline Yes No Atmosphere Yes No

Flow Correlation
Outlet Pressure (Psia)

Gas Turbulence Factor

Software Model Used



### Sand 1 Sand 2 Sand 3 Sand 4 Sand 5 Sand 6 Sand 7 Sand 8

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 4 of 5

### OCS PLAN INFORMATION FORM (CONTINUED)

Sand 1 Sand 2 Sand 3 Sand 4 Sand 5 Sand 6 Sand 7 Sand 8

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 information as part of an applicant’s Exploration Plan or Development Operations Coordination Documen t submitted for BOEM approval. We use the i nformation to facilitate our review and data entry for OCS plans. We will protect proprietary data according to the Freedom of Information Act and 30 CFR 550.197. An agency may not conduct or sponsor, and a person is no t required to respond to, a collectio n of information unless it displays a currently valid Office of Management 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 E xploration 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, an d completing and re viewing 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 5 of 599

109

124

125 126

139 SB003 (Respud)



### PROPOSED AT 618 SB003 LOCATION WATER DEPTH AND SEAFLOOR FEATURES MAP SB003 80

SB003
(Respud)



### BLOCK 618, ATWATER VALLEY, GULF OF MEXICOAmount 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; Barite28,216 bbls 314 bbl/day overboard / seafloorNoCuttings wetted with water-based fluidCuttings wetted with seawater,gel, and fresh water pad mudresidue from riserless holesections2,455 bbls27 bbl/day seafloorNoSynthetic-based drilling fluid amount adhering to cuttings Baroid AccoladeSBM2,070 bbls23 bbl/day overboardNoCuttings wetted with synthetic-based fluidCuttings wetted with residue ofBaroid Accolade SBM2,596 bbls29 bbl/day overboardNoWill humans be there? If yes, expect conventional wasteDomestic wasteKitchen waste24,750 bbls 275 bbl/day remove floating solidsand dischargeNoSanitary wasteSanitary waste7,110 bbls79 bbl/day chlorinate and dischargeNoIs there a deck? If yes, there will be Deck DrainageDeck DrainageRainfall & potable water16,200 bbls 180 bbl/day separate solids and0<15ppm overboardNoWill you conduct well treatment,completion, or workover?Well treatment fluidsNANANANANAWell completion fluidsWater Based Fluids and SeaWater2,000 bbls22 bbl/daydischarge used fluidsoverboardNoWorkover fluidsNANANANANAMiscellaneous discharges. If yes, only fill in thoseassociated with your activity.Desalinization unit dischargeMax capacity2,215,080 bbls 24,612 bbl/day overboardNoBlowout prevent fluidStack Magic ECO-FV24,500 bbls50 bbl/day overboardNoBallast waterSea Water105,750 bbls 1,175 bbl/day overboardNoBilge waterOil/Water Mixture2,250 bbls25 bbl/day 0<15ppm overboardNoExcess cement at seafloorClass H476 bbls5 bbl/day seafloorNoFire waterSea Water652,500 bbls 7,250 bbl/day overboardNoCooling waterSea Water40,487,400 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 - CR Luigsplease specify whether the amount reported is a total or per welCRLProjectedgenerated 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 & reusePipeline from dockBaroid 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,LA180 cu yds / well 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 56,250 lbs / well 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, LA360 bbls / well Recycle or fuelblendWash waterwater with trace amounts ofinternal olefin & esterPicked up at shorebase & trucked toprivate facilityNewpark EnvironmentalServices Inc., Fourchon, La1,000 bbls / well injectedChemical product wastespaint waste, chemicals,solvents, etc.N/AN/AN/AN/ATABLE 2. WASTES YOU WILL TRANSPORT AND /OR DISPOSE OF ONSHOREWaste DisposalWill 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 synthetic 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; Barite28,216 bbls 314 bbl/day overboard / seafloorNoCuttings wetted with water-based fluidCuttings wetted with seawater,gel, and fresh water pad mudresidue from riserless holesections2,455 bbls27 bbl/day seafloorNoSynthetic-based drilling fluid amount adhering to cuttings Baroid AccoladeSBM2,070 bbls23 bbl/day overboardNoCuttings wetted with synthetic-based fluidCuttings wetted with residue ofBaroid Accolade SBM2,596 bbls29 bbl/day overboardNoWill humans be there? If yes, expect conventional wasteDomestic wasteKitchen waste35,730 bbls 397 bbl/day remove floating solidsand dischargeNoSanitary wasteSanitary waste4,320 bbls48 bbl/day chlorinate and dischargeNoIs there a deck? If yes, there will be Deck DrainageDeck DrainageRainfall & potable water19,890 bbls 221 bbl/day separate solids and0<15ppm overboardNoWill you conduct well treatment,completion, or workover?Well treatment fluidsNANANANANAWell completion fluidsWater Based Fluids and SeaWater2,000 bbls22 bbl/daydischarge used fluidsoverboardNoWorkover fluidsNANANANANAMiscellaneous discharges. If yes, only fill in thoseassociated with your activity.Desalinization unit dischargeMax capacity119,520 bbls 1,328 bbl/day overboardNoBlowout prevent fluidStack Magic ECO-FV2383 bbls4 bbl/day overboardNoBallast waterSea Water45,000 bbls 500 bbl/day overboardNoBilge waterOil/Water Mixture2,250 bbls25 bbl/day 0<15ppm overboardNoExcess cement at seafloorClass H476 bbls5 bbl/day seafloorNoFire waterSea Water97,020 bbls 1,078 bbl/day overboardNoCooling waterSea Water59,710,410 bbls 663,449 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 - Invictusplease specify whether the amount reported is a total or per welProjectedgenerated wasteSolid and Liquid WastestransportationType 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 & reusePipeline from dockBaroid 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,LA180 cu yds / well 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 56,250 lbs / well 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, LA360 bbls / well Recycle or fuelblendWash waterwater with trace amounts ofinternal olefin & esterPicked up at shorebase & trucked toprivate facilityNewpark EnvironmentalServices Inc., Fourchon, La1,000 bbls / well injectedChemical product wastespaint waste, chemicals,solvents, etc.N/AN/AN/AN/ATABLE 2. WASTES YOU WILL TRANSPORT AND /OR DISPOSE OF ONSHOREWaste DisposalWill 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 synthetic 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 ValleyBLOCK574/618LEASEOCS-G 08038 / 08035PLATFORMNeptuneWELLSB003COMPANY CONTACTSusan WilsonTELEPHONE NO.713 599 6349REMARKSDrill and complete Well SB003 with Drillship (Invictus)FORM 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 0.00002 0.88 0.00803 0.0124 163.6 AP-42 3.1-2a &
Background 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. lb/hp-hr 0.0022 1.08E-05 0.031 0.0025141 0.00668 1.15 AP-42 3.3-1 10/96 Diesel Recip. < 600 hp. g/hp-hr 1 4.89E-03 14.06 1.14 3.03 521.6 AP42 3.3-1 10/96

Diesel Recip. < 600 hp.-EPA Tier 1 [2] g/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 1 [10] g/kW-hr 0.54 9.2 1.3 11.4 EPA Tier 1

Diesel Recip. < 600 hp.-EPA Tier 2 [3] g/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] g/kW-hr 0.3 4 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 0.000015 3.2 0.0819 0.85 163.6 AP-42 3.4-1 10/96

Diesel Recip. > 600 hp.-IMO Tier 1 (=> 2000

rpm) [5] g/kW-hr 9.8 7.2 IMO Tier 1

Diesel Recip. > 600 hp.-Marine Tier 1 (130-

1999 rpm) [6] 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.) [7] g/kW-hr 0.2 7.20 5.0 40CFR94.8(a)(2) 12/07

Diesel Recip. > 600 hp.-Invictus-Main [8] g/kW-hr 9.7 Main Engines

Manufacturer

Data

Diesel Recip. > 600 hp. lb/hp-hr 7.00E-04 1.08E-05 0.024 0.0007 0.0055 1.16 AP-42 3.4-1 10/96 Diesel Recip. > 600 hp. g/hp-hr 0.32 0.00 11 0.33 2.49 526.2 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 0.00009075 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 [9] 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] Diesel Recip. > 600 hp.-EPA Tier 1: PM, NOx, VOC and CO emission factors for EPA Tier 1 diesel engines. [9] BHPB utilizes Ultra Low Sulfur Diesel for all diesel combustion sources. Therefore, SO 2 emissions have been calculated based on a maximum sulfur content of 15 ppm in diesel fuel assuming that

100 percent of sulfur in the fuel is oxidized to SO 2

. [8] Diesel Recip. > 600 hp.-Invictus-Main: NOx emission factor is based on the TOI Invictus engine manufacturer's data. The mai n engines on Invictus are IMO Tier II certified engines. [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.-IMO Tier 1 (=> 2000 rpm): NOx emission factors for IMO Tier 1 diesel engines on certain cement uni t engines with rated engine rpm is equal to or greater than 2000.

[7] Diesel Recip. ≥ 37kw -Marine Tier 2: VESSELS: EPA Marine Engine Tier 2 for marine engines maunfactured after 2004 with a per cylinder displacem ent of 1.2 L - >5.0 L. [6] 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 8COMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKSBHP Billiton Pet. (GOM) Inc. Atwater Valley 574/618CS-G 08038 / 080Neptune SB003 Susan Wilson 713 599 6349OPERATIONS EQUIPMENT RATING MAX. FUEL ACT. FUEL RUN TIME MAXIMUM POUNDS PER HOURESTIMATED TONSDiesel Engines HP GAL/HRGAL/DNat. Gas Engines HP SCF/HR SCF/DBurners MMBTU/HR SCF/HR SCF/D HR/D DAYS PM SOx NOxVOC CO CO2 PM SOx NOxVOC CO CO2DRILLINGDP DRILLSHIP 64865 3132.98 75191.51 24 95 46.05 0.70 1047.17 54.77 378.57 75205.34 52.50 0.80 1193.78 62.43 431.57 85734.09PRIME MOVER>600hpdiesel[1] [2]56310 2719.77 65274.55 39.42 0.61 897.98 40.97 309.71 65319.60 0.00 0.00 0.00 0.00 0.00 0.00Emergency Generator>600hp diesel 2279 110.08 2641.82 1.60 0.02 54.70 1.66 12.53 2643.64 0.00 0.00 0.00 0.00 0.00 0.002-300 HP WIRELINE <600hpdiesel-POSU-CA PU Eng.[3]600 28.98 695.52 0.20 0.01 3.95 1.51 3.46 690.00 0.00 0.00 0.00 0.00 0.00 0.00WIRELINE <600hp diesel-GSU-W Generator 160 7.73 185.47 0.35 0.00 4.96 0.40 1.07 184.00 0.00 0.00 0.00 0.00 0.00 0.00WIRELINE <600hp diesel-Generator DHPS 160 7.73 185.47 0.35 0.00 4.96 0.40 1.07 184.00 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING <600hpdiesel-Batch Mixer[4]250 12.08 289.80 0.08 0.00 2.73 0.63 1.44 287.50 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING <600hpdiesel(Nitrogenpump)[5]490 23.67 568.01 0.44 0.01 7.41 1.05 9.18 563.50 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING >600hpdiesel[6]860 41.54 996.91 0.60 0.01 13.86 0.63 4.73 997.60 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING >600hpdiesel[6]860 41.54 996.91 0.60 0.01 13.86 0.63 4.73 997.60 0.00 0.00 0.00 0.00 0.00 0.00EMERGENCY EQUIP <600hp diesel-Fast Rescue 149 7.20 172.72 0.33 0.00 4.62 0.37 1.00 171.35 0.00 0.00 0.00 0.00 0.00 0.006-29HP EMERGENCY EQUIP <600hp diesel-Lifeboat 174 8.40 201.70 0.38 0.00 5.39 0.44 1.16 200.10 0.00 0.00 0.00 0.00 0.00 0.00EMERGENCY EQUIP <600hp diesel-Air Compressor 38 1.84 44.05 0.08 0.00 1.18 0.10 0.25 43.70 0.00 0.00 0.00 0.00 0.00 0.003-415 HP SEISMIC OP ENGINE <600hpdiesel[8]1245 60.13 1443.20 0.41 0.01 13.57 3.13 7.17 1431.75 0.00 0.00 0.00 0.00 0.00 0.00SLICKLINE <600hpdiesel[9]106 5.12 122.88 0.23 0.00 1.60 0.27 0.71 121.90 0.00 0.00 0.00 0.00 0.00 0.00FLUID FILTRATION PUMP <600hp diesel[10]174 8.40 201.70 0.09 0.00 1.14 0.44 1.43 200.10 0.00 0.00 0.00 0.00 0.00 0.00COIL TUBING POWER PACK <600hp diesel[11]260 12.56 301.39 0.23 0.00 3.93 0.56 4.87 299.00 0.00 0.00 0.00 0.00 0.00 0.00COIL TUBING PUMP >600hp diesel[12]750 36.23 869.40 0.67 0.01 11.34 1.60 14.06 870.00 0.00 0.00 0.00 0.00 0.00 0.00ECO CrewVESSELS>600hp diesel(crew) (main-4)[13]9000 434.70 10432.80 24 95 2.96 0.10 106.53 6.55 49.50 10440.00 3.37 0.11 121.45 7.46 56.43 11901.60VESSELS<600hp diesel(crew) (gens-3)[13]1083 52.31 1255.41 24 95 0.36 0.01 12.82 2.72 8.90 1245.45 0.41 0.01 14.61 3.10 10.15 1419.81Work/SupplyVESSELS>600hpdiesel(work)(main-2)[7]13196 637.37 15296.80 24 95 9.24 0.14 245.22 9.60 72.58 15307.36 10.53 0.16 279.56 10.94 82.74 17450.392 vesselsVESSELS>600hp diesel(work) (gen.-2)[7]8000 386.40 9273.60 24 95 5.60 0.09 132.18 5.82 44.00 9280.00 6.38 0.10 150.68 6.64 50.16 10579.20VESSELS>600hpdiesel(work)(SDT)[7]2200 106.26 2550.24 24 95 1.54 0.02 36.35 1.60 12.10 2552.00 1.76 0.03 41.44 1.82 13.79 2909.28VESSELS<600hp diesel(work) (E-Generator) 502 24.22 581.38 24 95 1.11 0.01 15.55 1.26 3.35 581.78 1.26 0.01 17.72 1.44 3.82 663.23INSTALLATION INSTALLATION Vessel >600hp diesel 4700 227.01 5448.24 24 4 3.29 0.05 112.80 3.42 25.85 17319.46 0.16 0.00 5.41 0.16 1.24 831.33jumper / flowline SUPPORT VESSEL >600hp diesel 17000 821.1 19706.40 24 4 11.90 0.18 408.00 12.37 93.50 62644.87 0.57 0.01 19.58 0.59 4.49 3006.95umbilical VESSELS>600hp diesel(supply) 12000 579.6 13910.40 24 4 8.40 0.13 288.00 8.73 66.00 44219.91 0.40 0.01 13.82 0.42 3.17 2122.562014 YEAR TOTAL (ANNUAL)90.44 1.43 2404.62 106.84 754.35 238796.17 77.34 1.23 1858.06 95.02 657.55 136618.44EXEMPTIONCALCULATIONDISTANCE FROM LAND IN MILES3729.60 3729.60 3729.60 3729.60 78999.49112Drill and complete Well SB003 with Drillship (Invictus)[7] 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 ismaximum/rated engine rpm. Vessel (Crew) maximum rpm is 1,800 per main engine. Vessel (Work) main engines maximum rpm are 1000rpm, and generators and SDT are 1800 rpm.[8] Diesel Recip. < 600 hp.-EPA Tier 2: PM, NOx, and CO emission factors for EPA Tier 2 diesel engines.[1] PRIME MOVER >600hp diesel-Invictus: TOI's Invictus maximum output per main engine is 9385 hp/7000 kW. These calculations conservatively assume operating 6 of 6 engines.[2] PRIME MOVER >600 hp. diesel-Invictus: NOx emission factor is based on the TOI Invictus engine manufacturer's data. The mainengines on Invictus are IMO Tier II certified engines.[3] Diesel Recip. < 600 hp.-EPA Tier 3: PM, NOx, and CO emission factors for EPA Tier 3 diesel engines on certain wireline andcement unit engines.[4] Diesel Recip. < 600 hp.-EPA Tier 2: PM, NOx, and CO emission factors for EPA Tier 2 diesel engines on certain wireline andcement unit engines.[5] 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.[6] Diesel Recip. > 600 hp.-IMO Tier I (=> 2000 rpm): NOx emission factors for IMO Tier I diesel engines on certain cement unit engines with rated engine rpm is equal to or greater than 2000.[13] 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.[9] Diesel Recip. < 600 hp.-EPA Tier 1: NOx emission factor for EPA Tier 1 diesel engines.[10] Diesel Recip. < 600 hp.-EPA Tier 3: PM, NOx, and CO emission factors for EPA Tier 3 diesel engines.[11] Diesel Recip. < 600 hp.-EPA Tier 1: PM, NOx, VOC and CO emission factors for EPA Tier 1 diesel engines.[12] Diesel Recip. > 600 hp.-EPA Tier 1: PM, NOx, VOC and CO emission factors for EPA Tier 1 diesel engines.FORM BOEM-139(October 2011 - Supersedes all previous versions of form BOEM-139 which may not be used).Page 3 of 8SUMMARYCOMPANY AREA BLOCK LEASE PLATFORM WELLBHP Billiton Pet. (GOM) Inc. Atwater Valley 574/618 OCS-G 08038 / 08035 Neptune SB003Emitted SubstanceYearPM SOx NOx VOC CO2014 77.34 1.23 1858.06 95.02 657.55Allowable3729.60 3729.60 3729.60 3729.60 78999.49FORM 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 08035PLATFORMWELLSB003COMPANY CONTACTKathy CampCRL713.201.9627REMARKSDrill / complete Well SB003 with CRLLEASE TERM PIPELINE CONSTRUCTION INFORMATION:YEAR NUMBER OF TOTAL NUMBER OF CONSTRUCTION DAYSPIPELINES2014 1 4FORM 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 uni t 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 displacem ent 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 8COMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKSBHP Billiton Pet. (GOM)Atwater Valley 574 OCS-G 08035 0 SB003 Kathy Camp 713.201.9627 Drill / complete Well SB003 with CRLOPERATIONS EQUIPMENT RATING MAX. FUEL ACT. FUEL RUN TIME MAXIMUM POUNDS PER HOUR ESTIMATED TONSDiesel Engines HP GAL/HR GAL/DNat. Gas Engines HP SCF/HR SCF/DBurners MMBTU/HR SCF/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 95 39.86 0.65 1451.87 43.29 229.96 61204.61 14.62 0.24 532.58 15.88 84.35 22451.15CRLPRIME MOVER>600hpdiesel[2] [3]47000 2270.10 54482.40 33.16 0.57 1315.12 34.19 186.99 53852.18 0.00 0.00 0.00 0.00 0.00 0.00CRANES<600hpdiesel[4] [5]1220 58.93 1414.22 2.69 0.01 37.66 3.01 8.15 1397.84 0.00 0.00 0.00 0.00 0.00 0.00Emergency Generator>600hp diesel 2064 99.69 2392.59 1.46 0.03 50.05 1.50 10.92 2364.87 0.00 0.00 0.00 0.00 0.00 0.00EMERGENCY EQUIP<600hp diesel 323 15.60 374.42 0.71 0.00 9.97 0.80 2.16 370.08 0.00 0.00 0.00 0.00 0.00 0.00WIRELINE <600hpdiesel-POSU-CA PU Eng.[6]300 14.49 347.76 0.10 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.[6]300 14.49 347.76 0.10 0.00 1.97 0.74 1.73 343.73 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING <600hpdiesel(Nitrogenpump)[7]490 23.67 568.01 0.44 0.01 7.41 1.05 9.18 561.43 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING >600hpdiesel[8]860 41.54 996.91 0.61 0.01 13.86 0.63 4.55 985.36 0.00 0.00 0.00 0.00 0.00 0.00CEMENTING >600hpdiesel[8]860 41.54 996.91 0.61 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 95 2.96 0.11 106.53 6.55 47.62 10311.95 3.37 0.12 121.45 7.46 54.29 11755.63VESSELS≥37kw diesel(crew)(gens-3)[9]1083 52.31 1255.41 24 95 0.36 0.01 12.82 2.67 8.90 1240.87 0.41 0.01 14.61 3.05 10.15 1414.59Work/SupplyVESSELS>600hp diesel(work) (main-2)[10]13196 637.37 15296.80 24 95 9.31 0.16 245.22 9.60 69.82 15119.62 10.61 0.18 279.56 10.94 79.60 17236.362 vesselsVESSELS>600hp diesel(work) (gen.-2)[10]4881 235.76 5658.33 24 95 3.44 0.06 80.65 3.55 25.83 5592.79 3.93 0.07 91.94 4.05 29.44 6375.78VESSELS>600hp diesel(work) (SDT)[10]2200 106.26 2550.24 24 95 1.55 0.03 36.35 1.60 11.64 2520.70 1.77 0.03 41.44 1.82 13.27 2873.60VESSELS<600hp diesel(work) (E-Generator) 502 24.22 581.38 24 95 1.11 0.01 15.48 1.24 3.35 574.64 1.26 0.01 17.65 1.41 3.82 655.09INSTALLATION INSTALLATION Vessel >600hp diesel 47000 2270.1 54482.40 24 4 33.16 0.57 1139.80 34.19 248.68 53851.31 1.59 0.03 54.71 1.64 11.94 2584.86jumper / flowline SUPPORT VESSEL >600hp diesel 17000 821.1 19706.40 24 4 11.99 0.21 412.27 12.37 89.95 19478.13 0.58 0.01 19.79 0.59 4.32 934.95umbilical VESSELS>600hp diesel(supply) 12000 579.6 13910.40 24 4 8.47 0.15 291.01 8.73 63.49 13749.27 0.41 0.01 13.97 0.42 3.05 659.972014 YEAR TOTAL (ANNUAL)152.07 2.59 5243.86 167.08 1029.21 244848.50 38.54 0.71 1187.68 47.27 294.22 66941.98EXEMPTIONCALCULATIONDISTANCE FROM LAND IN MILES3729.60 3729.60 3729.60 3729.60 78999.49112[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 AREA BLOCK LEASE PLATFORM WELLBHP Billiton Pet.Atwater Valley 574 OCS-G 08035 0 SB003Emitted SubstanceYearPM SOx NOx VOC CO2014 38.54 0.71 1187.68 47.27 294.22Allowable3729.60 3729.60 3729.60 3729.60 78999.49FORM 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 directing 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

1

1

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 Discharge ModelingNeptune SB03