UNITED STATES GOVERNMENT MEMORANDUM

To: Public Information (MS 5030)
Plans Section, Office of Field Operations (MS 5231)

Public Information copy of DOCD

Control # - S-07624

Type - Supplemental Development Operations Coordinations Document

Lease(s) - OCS-G24102 Block - 727 Mississippi Canyon Area OCS-G24107 Block - 771 Mississippi Canyon Area

Operator - Deep Gulf Energy II, LLC

Subsea Well 002 (MC 771) and Wells 001 (MC 727)

Not Found

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.

Karen Dunlap
Plan Coordinator

G24107/MC/771 G24107/MC/771 G24102/MC/727 G24102/MC/727 G24102/MC/727 4613 FSL, 6743 FWL
4926 FSL, 6710 FWL
4926 FSL, 6870 FWL
4926 FSL, 6870 FWL
4373 FSL, 6743 FWL G24102/MC/727 G24102/MC/727 G24102/MC/727 G24102/MC/727 G24102/MC/727 WELL/002 WELL/002 WELL/003 WELL/003 WELL/003 Botm Lse/Area/Blk Surface Location Surf Lse/Area/Blk Site Type/Name Description -

Rig Type - Subject: From: February 12, 2014Records of Changes – PUBLIC COPYPlan Control Number S-7624Supplemental Development Operations Coordination Document, Deep Gulf Energy II, LLC,OCS-G 24102/24107; Mississippi Canyon 727 / 771Date Section PageRemarks07/31/2013 All All Plan received by BOEM.09/09/2013 Cover Letter Revise the first number in the Unit Agreement.09/09/2013 1 5 Include previous activities.09/09/2013 1 7 Update storage tank total capacity (1, 3 and 4thtanks).09/09/2013 Attachment 1-A Include the end date for production. Update description of lease termpipelines.09/09/2013 2 Page 8 Update bonding statement.09/09/2013 4 Page 11 Added Request for H2s Determination.09/09/2013 7 Attachment 7-A Updated Waste Table including discharge rate and method.09/09/20138 Attachment 8-A Added AQR Reduction Measure chart.09/09/20139 Page 19 Referenced the plan the GB506 #004 WCD was verified under.09/09/201314 Page 25Included crew boats to the support vessel chart and updated diesel oilsupply vessels capacity as “gallons”.09/09/201316 Pages 27-29 and Attachment 16-AIncluded Texas CZM Enforceable Policies and a Texas CZMCertification.09/10/2013 2 Page 10 Updated bonding statement.09/11/2013 Cover Letter Revise from Initial DOCD to Supplemental DOCD09/24/2013 7 Attachment 7-A Updated waste table.09/24/2013 14 Attachment 14-A Updated waste table.09/27/2013 7 Attachment 7-A Removed discharge of synthetic based mud from waste table.01/09/2014 1 Attachments 1-A and 1-B Updated for new surface locations.01/09/2014 6 Attachment 6-A Updated for new surface locations01/09/2014 9 Pages 19 and 20Updated 9.1 to reflect OSRP approval and 9.4 comparison chart toreflect MC771 #002 as WCD in both DOCD and approved OSRP.01/10/2014 1 Attachment 1-A Update Surface Location E/W Departure01/10/2014 9 Pages 19 and 20 Include certification statement.01/30/2014 18 Page 31 Update bibliography to include OSRP Control Number.01/30/2014 All All Complete copy of Supplemental DOCD.PUBLIC COPY July, 2013



## UNIT DEVELOPMENT OPERATIONS COORDINATION DOCUMENT

KODIAK DEVELOPMENT UNIT UNIT CONTRACT NO. 754313008

Lease Numbers: OCS-G 24102 / 24107
Area/Block: Mississippi Canyon Blocks 727 / 771

Prospect Name: Kodiak
Offshore: Louisiana / Mississippi

Submitted by: Deep Gulf Energy II, LLC 738 Highway 6 South Suite 800 Houston, Texas 77079

Company Contact: Thomas E. Young (281) 596-0933 tyoung@deepgulfenergy.com

Estimated start-up date: September 2014

Authorized Representative: No. Copies Being Submitted: Kelley Pisciola Proprietary: 1 Copy & CD J. Connor Consulting, Inc. Public Info: 1 Copy & CD 16225 Park Ten Place, Suite 700 Houston, Texas 77084 For BOEM: (281) 578-3388 Plan No. kelley.pisciola@jccteam.com Assigned to:SECTION ATTACHMENTS

Section 1 Plan Contents 1-A OCS Plan Information Form
1-B Well Location Plat 1-C Pay.gov Receipt Section 2 General Information 2-A Blowout Assumptions and Worst Case Discharge Calculations Section 3 Geological, Geoph ysical Information 3-A Structure Contour Maps (Proprietary Plan Only) 3-B Interpreted Seismic Lines (Proprietary Plan Only) 3-C Geological Structure Cross Sections (Proprietary Plan Only) 3-D Shallow Hazard Assessments 3-E Stratigraphic Column (Proprietary Plan Only) Section 6 Biological, Physical and Socioeconomic Information 6-A Topograph ic Features Map Section 7 Wastes and Discharges Information 7-A Wastes You Will Gener ate, Treat and Downhole Dispose or Discharge to the GOM Section 8 Air Emissions Information 8-A Emissions Worksheets Section 9 Oil Spill Information 9-A Oil Spil l Response Discussion

9-B Worst Case Discharge Calculations and Assumptions (Proprietary Plan Only) Section 14 Support Vessels an d Aircraft Information 14-A Waste You Will Tr ansport and/or Dispose Onshore 14-B Vicinity Map Section 16 Coastal Zone Management Act Information 16-A Coastal Zone Cons istency Certification, Texas Section 17 Environmental Impact Analysis (EIA) 17-A Environmental Impact Analysis (EIA)TOC Pg 1 of 31 TABLE OF CONTENTS

SECTION 1 PLAN CONTENTS ..................................................................................... 5

1.1 PLAN INFORMATION ............................................................................................ 5

1.2 LOCATION ............................................................................................................. 5

1.3 SAFETY AND POLLUTION PR EVENTION F EATURES ....................................... 5

1.4 STORAGE TANKS AND PRODUCTION VESSELS .............................................. 7

1.5 POLLUTION PREVEN TION MEASU RES ............................................................. 7

1.6 ADDITIONAL MEASURES .................................................................................... 7

1.7 COST RECO VERY FEE ........................................................................................ 7

SECTION 2 GENERAL INFORMATION ........................................................................ 8

2.1 APPLICATIONS A ND PERMIT S ........................................................................... 8

2.2 DRILLING FLUIDS ................................................................................................. 8

2.3 PRODUCT ION ....................................................................................................... 8

2.4 OIL CHARACT ERISTICS ...................................................................................... 8

2.5 NEW OR UNUSUAL TECHNOLOGY .................................................................... 8

2.6 BONDING STATEMENT ........................................................................................ 8

2.7 OIL SPILL FINANCIAL RESP ONSIBILITY (OSFR) ............................................... 9

2.8 DEEPWATER WELL CO NTROL STAT EMENT .................................................... 9

2.9 SUSPENSION OF PRODUCT ION ........................................................................ 9

2.10 BLOWOUT SCENARIO ....................................................................................... 9

SECTION 3 GEOLOGICAL AND GEOPHYSICAL IN FORMATION ........................... 10

3.1 GEOLOGICAL D ESCRIPTION ............................................................................ 10

3.2 STRUCTURE CO NTOUR M APS ......................................................................... 10

3.3 INTERPRETED 3-D SEISMIC LI NES .................................................................. 10

3.4 GEOLOGICAL STRUCTU RE CROSS-SEC TIONS ............................................. 10

3.5 SHALLOW HAZA RDS REPO RT ......................................................................... 10

3.6 SHALLOW HAZARDS ASSESSMENT ................................................................ 10

3.7 HIGH-RESOLUTION SEISMIC LINES ................................................................. 10

3.8 STRATIGRAPHIC COLUMN ............................................................................... 10TOC Pg 2 of 31 3.9 TIME VS D EPTH TABL ES ................................................................................... 10

SECTION 4 HYDROGEN SU LFIDE INFORM ATION .................................................. 10

4.1 CONCENTRA TION .............................................................................................. 11

4.2 CLASSIFIC ATION ............................................................................................... 11

4.3 H2S CONTINGE NCY PLAN ................................................................................ 11

4.4 MODELING REPORT .......................................................................................... 11

SECTION 5 MINERAL RESOURCE CONSERVATION IN FORMATION .................... 12

5.1 TECHNOLOGY & RESERVOIR ENGINEERING PRACTICES AND
PROCEDUR ES .......................................................................................................... 12

5.2 TECHNOLOGY AND RECOVERY PR ACTICES AND PR OCEDURES .............. 12

5.3 RESERVOIR DE VELOPMEN T ............................................................................ 12

SECTION 6 BIOLOGICAL, PHYSICAL AN D SOCIOECONOMIC INFORMATION .... 13

6.1 DEEPWATER BENTHI C COMMUNITI ES ........................................................... 13

6.2 TOPOGRAPHIC F EATURES (BAN KS) ............................................................... 13

6.3 TOPOGRAPHIC FEATURES ST ATEMENT (SHU NTING) .................................. 13
6.4 LIVE-BOTTOMS (PINNACL E TREND FEAT URES) ............................................ 13
6.5 LIVE BOTTOMS (L OW RELI EF) ......................................................................... 13

6.6 POTENTIALLY SENSITIVE BIOLOGICAL F EATURES ...................................... 13

6.7 REMOTELY OPERATED VE HICLE (ROV) SURVEYS ....................................... 14

6.8 THREATENED AND EN DANGERED SPECIES, CRI TICAL HABITAT, AND

MARINE MAMMAL IN FORMATION .......................................................................... 14

6.9 ARCHAEOLOGICA L REPORT ............................................................................ 16

6.10 AIR AND WATER QUAL ITY INFORM ATION .................................................... 16

6.11 SOCIOECONOMIC INFORMAT ION .................................................................. 16

SECTION 7 WASTES AND DIS CHARGES INFO RMATION ...................................... 17

7.1 PROJECTED GENE RATED WAST ES ................................................................ 17

7.2 MODELING REPORT .......................................................................................... 17

SECTION 8 AIR EMISS IONS INFORM ATION ............................................................ 18

8.1 EMISSIONS WORKSHEETS A ND SCREENING QUESTIONS .......................... 18

8.2 SUMMARY IN FORMATION ................................................................................. 18

SECTION 9 OIL SPI LL INFORMAT ION ...................................................................... 19TOC Pg 3 of 31 9.1 OIL SPILL RESPON SE PLANNI NG .................................................................... 19

9.2 SPILL RESPON SE SITES ................................................................................... 19

9.3 OSRO INFO RMATION ........................................................................................ 19

9.4 WORST-CASE DISCHARGE SC ENARIO DETERM INATION ............................ 19

SECTION 10 ENVIRONMENTAL MO NITORING INFO RMATIO N .............................. 21

10.1 MONITORING SYSTEMS .................................................................................. 21

10.2 INCIDENTAL TAKES ......................................................................................... 21

10.3 FLOWER GARDEN BANKS NAT IONAL MARINE SANCTUARY ..................... 21

SECTION 11 LEASE STIPUL ATIONS INFORM ATION .............................................. 22

11.5 MARINE PROTEC TED SPEC IES ..................................................................... 22

SECTION 12 ENVIRONMENTAL MITIGA TION MEASURES IN FORMATION ........... 23

12.1 MEASURES TAKEN TO AVOID, MI NIMIZE, AND MITIGATE IMPACTS .......... 23

12.2 INCIDENTAL TAKES ......................................................................................... 23

SECTION 13 RELATED FACILITIES AND OPERATIONS IN FORMATION .............. 24

13.1 RELATED OCS FACILI TIES AND OPER ATIONS ............................................. 24

13.2 TRANSPORTAT ION SYSTEM .......................................................................... 24

13.3 PRODUCED LIQUID HYDROCARBON S TRANSPORTATION VESSELS ....... 24

SECTION 14 SUPPORT VESSELS AN D AIRCRAFT INFO RMATION ...................... 25

14.1 GENE RAL .......................................................................................................... 25

14.2 DIESEL OIL SU PPLY VES SELS ....................................................................... 25

14.3 DRILLING FLUID TR ANSPORTAT ION ............................................................. 25

14.4 SOLID AND LIQUID W ASTE TRANSPOR TATION ........................................... 25

14.5 VICINITY MAP ................................................................................................... 25

SECTION 15 ONSHORE SUPPORT FACILITIES INFO RMATION ............................ 26

15.1 GENE RAL .......................................................................................................... 26

15.2 SUPPORT BASE CONSTRUCT ION OR EXPAN SION ..................................... 26

15.3 SUPPORT BASE CONSTRUCTION OR EXPANSION TIMETABLE ................ 26

15.4 WASTE DI SPOSAL ........................................................................................... 26

SECTION 16 COASTAL ZONE MANAG EMENT (CZM) IN FORMATION ................... 27

SECTION 17 ENVIRONMENTAL IMPACT ANALYSI S (EIA) ..................................... 30

SECTION 18 ADMINISTRAT IVE INFORM ATION ........................................................ 31TOC Pg 4 of 31 18.1 EXEMPTED INFORMAT ION DESCRI PTION .................................................... 31

18.2 BIBLIOGR APHY ................................................................................................ 31Deep Gulf Energy II, LLC Section 1 – Pg. 5 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 1
PLAN CONTENTS

1.1 PLAN INFORMATION Effective February 1, 2013, Mississippi Cany on Blocks 727 (S/2) and 771 (N/2), (Leases OCS-G 24102 and 24107 respectively) were unitized under Unit Contract No. 754313008 (Mississippi Canyon (MC) Block 727 Unit (Kodiak Unit)). Deep Gulf Energy II, LLC (DGE II) as designated operator of t he subject unit hereby submits this Unit Development Operations C oordination Document.

DGE II proposes to drill, complete and produc e two well locations and two lease-term pipelines. The subsea system will include the instal lation of (2) subsea trees, (2) leaseterm jumper pipelines, a bulk right-of-way pi peline, flowline end termination (FLET), an umbilical termination assembly (UTA) and asso ciated electrical/optical/hydraulic flying leads. These development operations are in approximately 4833 feet of water. The wells will be drilled with a dynamically positioned semi-submersible MODU. The right-ofway pipeline, lease term pipelines and um bilical system will be installed using a dynamically positioned lay barge.

A Development Operations Coordination Document (N-8279) was submitted by Dominion Exploration & Production, Inc. on November 19, 2004 and approved on January 20, 2005. The plan provided for t he production of Mississippi Canyon Block 771, Lease OCS-G 24107 (Goldfinger SS005), and th e installation of a jumper pipeline to tie the well into the flowline. To date, the jumper has been insta lled, and the well has been placed on continuous production.

The OCS Plan Information Form BOEM-137 is included as Attachment 1-A.

1.2 LOCATION Well Location Plats depicting the proposed surface and bottomhole locations of the proposed wells, measured depth/total vertical depth and water depth for each location
are included as Attachment 1-B . Operations proposed in this plan will be conducted using dynamically positioned vessels; theref ore, there will be no associated anchors.

1.3 SAFETY AND POLLUTION PREVENTION FEATURES Safety of personnel and protection of the environment during the pr oposed operations is one of the primary concerns of DGE II. DGE II mandates regul atory compliance with the
contractors and vendors associated with the proposed operations as follows:Deep Gulf Energy II, LLC Section 1 – Pg. 6 of 31 Unit DOCD July, 2013 Kodiak Development Unit The Bureau of Ocean Energy Management (BOEM) mandates t hat the operations described in this Initial DOCD comply with well control, pollution prevention, construction, welding procedures, and traini ng described in BSEE regulations 30 CFR 250 C, D, E, O and S; and as further clarified by BSEE Notices to Lessees.

The Bureau of Safety and Environmental Enforcement (BSEE) conducts periodic announced and unannounced onsite inspections of offshore facilities to confirm operators are complying with lease stipul ations, operating r egulatory 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.

U.S. Coast Guard regulations contained in Title 33 CFR Part 144 mandate that appropriate life rafts, life jackets, ring buoys, et c. be maintained on the facilities at all
times.

U.S. Environmental Protecti on Agency regulations contai ned in the NPDES General Permit GMG290000 mandate that supervisory and certain designated personnel onboard the facility be familiar with the effluent limitations and guidelines for overboard discharges into the receiving waters.

A description of the dr illing unit is included on the OCS Plan Information Form which complies with all relevant regulations. Rig specifications will be made part of each Application for Permit to Drill. DGE II will drill these wells with a dynamically positioned
semi-submersible MODU which will be equipped with a Subsea BOP. Once a rig is contracted, BOP information and schematics will be included as a part of the Application
for Permit to Drill.

Safety features on the drilli ng unit will include we ll control, pollution prevention, and blowout prevention equipment as described in BSEE regulations 30 CF R 250 C, D, E, O and S; and as further clarifi ed by BSEE Notices to Lessees, and current policy making invoked by the BSEE, Environmental Protec tion Agency and the U.S. Coast Guard. Appropriate life rafts, life jackets, ring buoys, et c., will be maintained on the facility at all
times.

Pollution prevention measures include installation of curb s, gutters, drip pans, and drains on drilling deck areas to co llect all contaminants and debris.Deep Gulf Energy II, LLC Section 1 – Pg. 7 of 31 Unit DOCD July, 2013 Kodiak Development Unit 1.4 STORAGE TANKS AND PRODUCTION VESSELS All facility tanks with a capacity of 25 bbls or more.

Type of Storage

Tank Type of Facility Tank Capacity

(bbls) Number of Tanks Total Capacity

(bbls) Fluid Gravity

(API) Fuel Oil (day/settling tanks) DP Semisubmersible 360/256/161 3 777 No.2 Diesel

Emergency Generator Fuel Oil DP Semisubmersible 31 1 31 No. 2 Diesel

Fuel Oil (port) DP Semisubmersible 4541/3396 2 7937 No. 2 Diesel Fuel Oil (stb) DP Semisubmersible 4541/3396 2 7937 No. 2 Diesel

Lube Oil DP Semisubmersible 116 1 116 26°

Waste Oil DP Semisubmersible 38/28 2 66 26°
Oily Water (port) DP Semisubmersible 186/178 2 364 N/A
Oily Water (stb) DP Semisubmersible 186/178 2 364 N/A

1.5 POLLUTION PREVENTION MEASURES These operations do not propose activities for wh ich the State of Florida is an affected state; therefore, relevant information is not required.

1.6 ADDITIONAL MEASURES DGE II does not propose any additional safety, pollution pr evention, or early spill detection measures beyond those required by 30 CFR Part 250.

1.7 COST RECOVERY FEE A pay.gov receipt in the amount of $8,476.00 to cover the cost recovery fee associated with this plan is included as Attachment 1-C.U.S. Department of the Interior 

### ATTACHMENT 1-A
Bureau of Ocean Energy Management

Have you previously provided informa tion to verify the calculations and assumptions for your WCD? Yes X No

If so, provide the Control Number of the EP or DOCD with which this information was provided

Do you propose to use new or unusual technol ogy to conduct your activities? Yes X No

Do you propose to use a vessel with anchors to install or modify a structure? Yes X No

Do you propose any facility that will serve as a host f acility for deepwater subsea development? Yes X No Description of Proposed Activities and Tentative Schedule (Mark all that apply)

Proposed Activity Start Date End Date No. of Days

Drill and Complete Well Location A – MC771 #002 09/01/2014 04/18/2015 229

Install Lease Term Jumper Pipeline 04/24/2015 04/30/2015 7

Commence Production from Location A – MC772 #002 05/15/2015 05/15/2025 10 years

Drill and Complete Well Location B – MC727 #003 01/01/2016 08/17/2016 229

Install Lease Term Jumper Pipeline 08/25/2016 08/31/2016 7

Commence Production from Location B – MC727 #003 09/18/2016 09/18/2026 10 years

Description of Drilling Rig Description of Structure

Jackup Drillship Caisson Tension leg platform

Gorilla Jackup Platform rig Fixed platform Compliant tower

Semisubmersible Submersible Spar Guyed tower

X DP Semisubmersible Other (Attach description) Floating production system Other (Attach description) Drilling Rig Name (If known): Ensco Seri es 8500 equivalent or similar MODU Description of Lease Term Pipelines

From (Facility/Area/Block) To (Facility/Area /Block) Diameter (Inches) Length (Feet)

Well Location A – MC771 #002 MC727 FLET 8-inch 85

Well Location B – MC727 #003 MC727 FLET 8-inch 85

Form BOEM- 0137 (December 2011 – Supersedes all previ ous editions of this form which may not be used.) Page 1 of 4 General Information

Type of OCS Plan: Exploration Plan (EP) Develo pment Operations Coordination Document (DOCD) X

Company Name: Deep Gulf Energy II, LLC BOEM Operator Number: 02985

Address: 738 Highway 6 South, Suite 800 Contact Person: Kelley Pisciola

Houston, TX 77079 Phone Number: 281-698-8519

E-Mail Address: kelley.pisciola@jccteam.com

If a service fee is required unde r 30 CFR 550.125(a), provide the Amount paid $8476.00 Receipt No. NA Project and Worst Case Discharge (WCD) Information

Lease(s): G24102 / 24107 Area: Mississippi Canyon Block( s) 727 / 771 Project Name (If Applicable): Kodiak

Objective(s) X Oil Gas Sulphur Salt Onshore Support Base(s): Fourchon, LA

Platform / Well Name: MC771 Well No. 002 Total Volume of WCD: 14,974,192 bbls API Gravity: 35°

Distance to Closest Land (Miles): 54 Volume from uncontrolled blowout: 107,728 bbls/day OCS PLAN INFORMATION FORM OMB Control Number: 1010-0151 OMB Approval Expires: 12/31/14OCS 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): A - MC771 #002 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.

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

WCD Info For wells, volume of uncontrolled blowout (Bbls/Day): 107,728 For structures, volume of all storage and pipelines (Bbls): N/A API Gravity of fluid 35°

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

Lease No. OCS-G 24102 OCS
OCS

Area Name Mississippi Canyon

Block No. 727

Blockline Departures (in feet) N/S Departure 4,926.00’ FSL N/S Departure N/S Departure F __ L N/S Departure F __ L N/S Departure F __ L

E/W Departure 6,710.00’ FWL E/W Departure E/W Departure F __ L E/W Departure F __ L E/W Departure F __ L

Lambert X-Y coordinates X: 1,052,150.00’ X: X:
X:
X:

Y: 10,253,406.00’ Y: Y:
Y:
Y:

Latitude/ Longitude Latitude 28° 14’ 32.9302” Latitude Latitude
Latitude
Latitude

Longitude 88° 49’ 39.1139” Longitude Longitude Longitude Longitude

Water Depth (Feet): 4,818’ MD (Feet): TVD (Feet): MD (Feet): MD (Feet): MD (Feet): TVD (Feet): TVD (Feet): TVD (Feet): Anchor Radius (if applicable) in feet: N/A
Anchor Locations for Drilling Rig or Construction Barge (If anchor radius supplied above, not necessary)

Anchor Name or No. Area Block X Coordinate Y C oordinate Length of Anch or 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 previ ous editions of this form which may not be used.) Page 2 of 4OCS 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): B - MC727 #003 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.

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

WCD Info For wells, volume of uncontrolled blowout (Bbls/Day): 107,728 For structures, volume of all storage and pipelines (Bbls): N/A API Gravity of fluid 35°

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

Lease No. OCS-G 24102 OCS
OCS

Area Name Mississippi Canyon

Block No. 727

Blockline Departures (in feet) N/S Departure 4,926.00’ FSL N/S Departure N/S Departure F __ L N/S Departure F __ L N/S Departure F __ L

E/W Departure 6,870.00’ FWL E/W Departure E/W Departure F __ L E/W Departure F __ L E/W Departure F __ L

Lambert X-Y coordinates X: 1,052,310.00’ X: X:
X:
X:

Y: 10,253,406.00’ Y: Y:
Y:
Y:

Latitude/ Longitude Latitude 28° 14’ 32.9548” Latitude Latitude
Latitude
Latitude

Longitude 88° 49’ 37.3251” Longitude Longitude Longitude Longitude

Water Depth (Feet): 4,823’ MD (Feet): TVD (Feet): MD (Feet): MD (Feet): MD (Feet): TVD (Feet): TVD (Feet): TVD (Feet): Anchor Radius (if applicable) in feet: N/A
Anchor Locations for Drilling Rig or Construction Barge (If anchor radius supplied above, not necessary)

Anchor Name or No. Area Block X Coordinate Y C oordinate Length of Anch or 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 previ ous editions of this form which may not be used.) Page 2 of 4MC_727

MC_771 1 1 3 4 5 6

1

1 2

3

2



### Deep Gulf Energy II, LLC

Kodiak MC 727-771



### Well Surface Locations

Base Map 0 12000 ft 4000 8000

Scale = 1:48000 X/Y: FeetX=1,061,280’X=1,045,440’ Y = 10,264,320’’

Y = 10,248,480 

### ’

Y = 10,232,640 

### ’ Surface Location
OCS

‐ G 24107 Well No. 2

X = 1,,052,150.00’

Y = 10,253,406.00’

Lat: 28 ° 14’ 32.9302” N Long: 88 ° 49’ 39.1139” W 6,710’ FWL of MC 727 4,926’ FSL of MC 727

PTD: 29,769’md 28,350’tvd

Water Depth 4,818’

Surface Location
OCS

‐ G 24102 Well No. 3

X = 1,052,310.00’

Y = 10,253,406.00’

Lat: 28 ° 14’ 32.9548” N Long: 88 ° 49’ 37.3251” W 6,870’ FWL of MC 727 4,926’ FSL of MC 727

PTD: 27,589’md 26,075’tvd

Water Depth 4,823’1 Kelley Pisciola

From: paygovadmin@mail.doc.twai.gov

Sent: Friday, July 26, 2013 8:46 AM

To: Ruth Strange Subject: Pay.gov Payment Confirmation: BOEM Development/DOCD Plan - BD

Your payment has been submitted to Pay.gov and the details are below. If you have any questions or wish to cancel this
payment, you will need to contact Wendy Yanez at (504) 736

‐ 2818.

Application Name: BOEM Development/DOCD Plan ‐ BD Pay.gov Tracking ID: 25BNBB96 Agency Tracking ID:

74481773863

Account Holder Name: Deep Gulf Energy II, LLC Transaction Type: ACH Debit Transaction Amount: $8,476.00 Payment

Date: Jul 29, 2013 Account Type: Business Checking Routing Number: 121000248 Account Number: ************3536

Transaction Date: Jul 26, 2013 9:45:53 AM Total Payments Scheduled: 1 Frequency: OneTime

Region: Gulf of Mexico

Contact: Kelley Pisciola 281

‐ 698

‐ 8519 Company Name/No: Deep Gulf Energy II, LLC, 02985 Lease Number(s): 24102, 24107,

, , Area

‐ Block: Mississippi Canyon MC, 727: Mississippi Canyon MC, 771:

, : , : , Type

‐ Wells: Initial Plan, 2

THIS IS AN AUTOMATED MESSAGE. PLEASE DO NOT REPLY.Deep Gulf Energy II, LLC Section 2 – Pg. 8 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 2
GENERAL INFORMATION

2.1 APPLICATIONS AND PERMITS
Listed in the table below are the additional applications/permits to be filed before operations can commence under this DOCD.

Application/Permit Issu ing Agency Status APD BSEE To be Submitted Surface Commingling Applicat ion BSEE To be Submitted Deepwater Operations Plan BSEE To be Submitted Conservation Information Document BOEM Submitted 07/30/2013 Lease Term Pipeline Application BSEE To be Submitted ROW Pipeline Application BSEE To be Submitted Suspension of Production BSEE To be Submitted

2.2 DRILLING FLUIDS The following table provides information on the types and amounts of the drilling fluids DGE II plans to use to drill the proposed wells.

Type of Drilling Fluid Estimated Volume of Drilling Fluid to be Used per Well Water-based 40000 bbls/well Oil-based (diesel, minerals) N/A Synthetic-based 20000 bbls/well

2.3 PRODUCTION Proprietary Information

2.4 OIL CHARACTERISTICS Proprietary Information

2.5 NEW OR UNUSUAL TECHNOLOGY No new or unusual technology is proposed in this DOCD.

2.6 BONDING STATEMENT The bond requirements for the activities and facilities proposed in this DOCD are satisfied by both a lease-specific bond for OCS-G 24102 and a $3,000,000.00 areawide bond for OCS-G 24107, furnished and main tained according to 30 CFR 256, subpart I; NTL No. 2000-G16, "Guidelines for General Lease Surety Bonds;" andDeep Gulf Energy II, LLC Section 2 – Pg. 9 of 31 Unit DOCD July, 2013 Kodiak Development Unit additional security under 30 CFR 256. 53(D) and National NTL 2008-N07, “Supplemental Bond Procedures.”

2.7 OIL SPILL FINANCIAL RESP ONSIBILITY (OSFR) Deep Gulf Energy II, LLC, BOEM compan y number 02985 has demonstrated or will demonstrate oil spill financial responsibilit y for the facilities proposed in this DOCD according to 30 CFR Part 553; and NTL 2008-N05, "Guideli nes for Oil Spill Financial Responsibility for Covered Facilities."

2.8 DEEPWATER WELL CONTROL STATEMENT Deep Gulf Energy II, LLC, BOEM company number 02985, has the financial capability
to drill a relief well and conduct other emergency well control operations.

2.9 SUSPENSION OF PRODUCTION The subject leases are currently held by a un it suspension of production approved from June 1, 2013 through April 30, 2014. An additional unit su spension of production will be requested in 2014.

2.10 BLOWOUT SCENARIO In accordance with NTL 2010-N06, “Informa tion Requirements for Exploration Plans, Development and Production Plans, and De velopment Operations Coordination Documents on the OCS,” the blow out scenario is included as Attachment 2-A.

### ATTACHMENT 2-A

Blowout Scenario

Estimated maximum flow rate

The estimated maximum flow rate would occur in the objective section, if a kick were taken and the well blew out. The maximum Worst Case Discharge (WCD) modeled for this scenario is 107,728 BOPD.

Maximum duration of blowout (days)

The duration of the bl owout will be a function of the we ll bridging over, the ability of surface intervention to shut-in or contain the well or, as a last resort, drilling a relief well to kill the blowout. T he expected maximum time frames fo r uncontrolled flow in each of the different operational out comes would be as follows:

 Bridging Over in 2 Days,

 Surface Intervention in 15 Days,

 A Relief Well in 139 Days.

Maximum discharge volume The following table is a linear estimate of the maximum discharge volume for each of the aforementioned operati onal outcomes assuming no reservoir depletion.
Operational

Outcome Maximum Discharge Rate (bbl/day) Discharge Duration

(days) Maximum Discharge Volume (bbl)

Bridging Over 107,728 2 215,456

Surface Intervention 107,728 15 1,615,920

Relief Well 107,728 139 14,974,192

Potential of wellbore to br idge over during a blowout
There is significant potential for the well bore to bridge over during the WCD blowout. Bridging is likely to occur due to t he extreme drawdown calculated between the formation and the open hole section. A Merlin reservoir simulation model was used to investigate the well conditions during the WCD blowout scenario. The estimated reservoir pressure is 21,167 psi. The rese rvoir model estimates bottom hole flowing pressures, based upon reservoir properties and flow rates. The calculated delta reservoir pressure (initial re servoir pressure minus flowing BHP at Day 1 WCD rate) is modeled to be 11,875 psi.In our experience in the deepwater GOM, we strive to limit the estimated total drawdown on a producing interval to reduce t he risk of wellbore collapse and sand/fines migration into a well. We limit the drawdown to typicall y less than 4,000 psi by reducing the rates the wells produce and by completing each well wi th a cased hole, frac-pack completion.
There is a strong likelihood of wellbore bridging over as:

 Drawdown is estimated to be near ly 3 times greater than our operating practices,

 The blowout occurs in a long open hole section of the well, with no benefit of casing or a frac-pack completion,

 If any water zones are exposed this will accelerate we llbore collapse and bridging,

Surface intervention to stop the blowout
In the event of a blowout and assuming the bl owout prevention equipment is still intact; the subsea BOP will be used for successful shut -in of the well. The well would then be killed and re-entered to eit her abandon or return to norma l operations. Surface intervention would be the first line of defens e after a blowout occurs. The specific intervention technique chosen will depend on ac tual conditions and ability to access the existing well.
In the event that the subsea BOP is inoperabl e, the surface intervention would employ the Helix Well Contai nment Group (HWCG) containment system to achieve successful containment of the well. T he system will be empl oyed, while simultaneously initiating relief well planning and operat ions. Specifics will be submitted within the Well Containment Plan with the APD.
Typically blowouts can be controlled with surf ace intervention, with a good likelihood of success and in a relatively short time fram e, as long as, the subsea casing, wellhead and BOP’s are not damaged beyond use. The intervention technique chosen will depend on actual conditions and ability to a ccess the existing well. There can be simple solutions such as rig up and bullhead kill mud or more complex solutions, but the solution will depend on wellbore conditions.

Surface intervention time estimate
The assumption is that the well has an unc ontrolled blowout and the MODU has sunk with displacement from the well head. Additionally, it assumes that debris removal will be required to gain access to the subsea BO P system. The ROV has been deployed and was unsuccessful in shutting in the well, us ing the existing subsea BOP control panel. The scenario employs one of the aforementioned containment system’s capping BOPs.
The table on the next page describes the estima ted time required to shut in and secure the well using the containment system or capping stack. Note that these operations all basically start at the same point in ti me and are performed in parallel. The entire operation is estimated to take 15 days from start of site assessment until the capping stack has been deployed and the well shut in.Duration of a well capping operation
Operation Incremental Duration

(days) Cumulative Time Since Event Start (days) Assess wellbore conditions for surface intervention requirements. Conduct notifications to the regulatory agencies and primary contractors. Well capping and/or cap and flow operations which include mobilization, deployment, and installation of the well containment system 2 2

Site Preparation which includes mobilizing and deploy ment of the IWOCS System and Dispersant System. 5 7

Debris removal including mobilization of ROV boat and construction support vessel and execution of debris removal plan. 7 14

Run cap and seal well. 1 15

Relief Well
It is preferred to drill relief wells from an open water location, rather than a platform location. Open water locations provide the best option on designing a simpler intercept well and allow a greater choice on rig avail ability. There are not any platforms in the immediate vicinity; therefore, it is not feasible to consider as a relief well location.

Relief well location and drilling strategy
The surface location for a relief well(s) is a function of s eabed bottom and shallow hazard conditions, current, wind direction and wellbore access. The relief well surface location for the MC 771 Well No. 002 (drilled from Well Site A surface location) could be drilled from an appropriately clea red-of-hazards surface loca tion to the south-southwest or north-northwest of the Well Site A locati on. DGE II has investigated ten (10) surface location sites in MC 727. Two (2) of the surf ace location sites investigated resulted in Well Site A (planned MC 771 Well No. 002 location) and Well Site B (planned MC 727 Well No. 003 location). Two (2) other surf ace location sites investigated (one approximately 2900’ s outh-southwest of Well Site A, one approximately 2800’ northnorthwest of Well Site A) would be appr opriate for relief well locations.A relief well for MC 771 Well No. 002 would be designed to intersect the blowout well below the 14” or 11-7/8” casing point. Once the well is intersected, kill pumping operations would be initiated to kill the blowout well.
Relief well design approach for other locati ons would be very similar, with other approved surface locations used to initiate relief wells.

Relief well rig availability
The rigs listed below could be availa ble for relief well operations:

Rig Name Contractor Rated Water Depth MODU Type Rig Status

Ensco 8500 Ensco 8,500’ DP Semisubmersible Contracted GOM Ensco 8501 Ensco 8,500’ DP Semisubmersible Contracted GOM Ensco 8505 Ensco 8,500’ DP Semisubmersible Contracted GOM West Sirius Seadrill 10,000’ DP Semisubmersible Contracted GOM Maersk Developer Maersk 10,000’ DP Semisubmersible Contracted GOM Danny Adkins Noble 12,000’ DP Semisubmersible Contracted GOM C.R. Luigs Transocean 10,000’ DP Drill Ship Contracted GOM Discoverer Deep Seas Transocean 10,000’ DP Dr ill Ship Contracted GOM

Relief well package constraints
The proposed rigs for relief well operati ons have suitable drilling packages with sufficient capabilities to work in the subjec t water depths and drill to the required relief well depth. The BOP systems have met the BSE E certification requirements and will be re-inspected in transit, prior to drilling a reli ef well to the required true vertical depth.

Relief well rig contract and mobilization timing
A suitable rig could be sele cted and a contract finalized in 48 hours after undertaking the decision to begin relief well operations. Backup tubular s and wellhead systems are maintained in stock for each well. Mobilizat ion of equipment and services to the rig for the relief well could be completed while opera tions required to suspend the rig’s current activity were taking place. The time requir ed to contract, mobilize, drill a relief well and kill the blowout well is estimated at 139 days and is summarized below:Duration of relief well
Description Days Cumulative Days
Well Control Assessment. Identify suitable MODU for relief well operations 2 2

MODU suspends operations from current well. Contract to be executed and Well Spud Equipment is mobilized 14 16

Mobilize Rig and instal l 36” Structural Casing 8 24

Spud and drill to the top of the zone of interest and set casing. 105 129

Mag-Range relief well into intersecting position. 5 134

R/U pumping equipment and kill well. 5 139
R/D Pumping Equipment, PA Wellbore, Pull Riser, and Demobilize 15 154

Blowout Prevention and Intervention
Summary of prevention measures

DGE II has maintained a safe track record of prudent operations in the GOM deepwater environment. We will continue to implement it s safe operating practices to enhance its operating risk reduction program. In addition to the safe operating practices, the following measures will be implemented into well design, drilling and completion operations.

 BOP Certification, BOP Drills, Pit Drill’s and all ot her required BSEE testing requirements,

 Current Well Control Certification fo r all Drilling and Completion Rig Site Supervisors,

 Taking Slow Pump Rate measurement s during all open hol e operations and critical cased hole operations,

 Updating Kill Sheets duri ng each tour and posting the same on the rig floor,

 Maintain a current BOP to RKB spaceout Chart,

 Monitoring wellbore fill-ups and displace ments during trips, by the Well Site Supervisor,

 Maintain the necessary circulating sw ages, TIW Valves and IBOP on the rig floor at all times during operations and f unction test these valves during each
tour.

The utilization of Pre-Job Sa fety meetings will continue to be implemented prior to each operation with all of the rig cr ews. These are intended to create a behavior based safety program and promote an at mosphere within the DGE II and rig crew interface, such thata “Stop the Job” mentality is promoted across the rig c ontractor’s crew, empowering every crew member to question the safety of each operation.

Early well control intervention

In the event of a blowout situation, due to failed BOP equipment and uncontrolled flow at the seafloor or at surfac e, assuming all other surface controlled actuation measures have failed or are inaccessible, a ROV will fly into position at the BOP subsea actuation panel and actuate the shear ram or pipe rams to establish containment.
If the riser system and rig have been compromis ed, then debris removal will be initiated to obtain clear access to the BOP. A C apping Stack will be employed to achieve successful containment of the well. Once containment is es tablished and wellbore pressure testing and assessment is complet ed by DGE II and Well Control Specialists, well kill operations can be initiate d through the existing wellbore.

Well control engineering services
DGE II has a service agreement in place with Boots and Coots International Well Control. In the event of a blowout situation, these companies will be contacted to assist in the detailed design and impl ementation of well control and/ or relief well operations.

Additional prevention & mitigation techniques
Pursuant to wellbore cementing and zonal isolation techniques, all cementing operations will be modeled a nd designed under the guideli nes set forth in API Recommended Practice 65 Part 1 & 2. Operations will be dictated by the rules and requirements set forth in Federal Regu lations, under the wellbore cementing requirements.
API Standard 53 Blowout Prevention Equi pment Systems for Drilling Wells and Recommended Practice 16Q for Marine Drilling Risers will be used as the guidelines for installation, testing and maintenance of the surface and subsea Marine Risers and BOP systems. The purpose of these recommended practices is to provide information that can serve as a guide for installation and te sting of blowout prevention systems has contracted for floating marine drilling rigs.
The goal of using these re commended practices is to assi st DGE II operations in promoting personnel safety, public safety, and integrity of the drilling equipment and preservation of the environment for float ing marine drilling operations. These recommended practices help to facilitate the broad availability of proven, sound engineering and operati ng practices.
These practices are considered acceptab le for accomplishing BOP and Marine Riser associated operations. However, equivalent alternative installations and practices may be utilized to accomplish the same obj ectives. When using these recommended practices or other alternatives, DGE II wi ll insure that operations comply with requirements of Federal Regulations.Deep Gulf Energy II, LLC Section 2 – Pg. 10 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 3
GEOLOGICAL AND GEOPHYSICAL INFORMATION

3.1 GEOLOGICAL DESCRIPTION Proprietary Information

3.2 STRUCTURE CONTOUR MAPS Proprietary Information

3.3 INTERPRETED 3-D SEISMIC LINES Proprietary Information

3.4 GEOLOGICAL STRUCTURE CROSS-SECTIONS Proprietary Information

3.5 SHALLOW HAZARDS REPORT Proprietary Information

3.6 SHALLOW HAZARDS ASSESSMENT
In accordance with NTL 20 08-G05, Shallow Hazards Program” (Extended by NTL BOEM 2013-G02, “Extens ion of Prior Notices to Lessees”), a 3-D seismic shallow hazards assessment has been prepared for each proposed surface locations, evaluating seafloor and s ubsurface geological and manm ade features and conditions that may adversely affect drilling operations. The shal low hazards assessment is
included as Attachment 3-D

.

3.7 HIGH-RESOLUTION SEISMIC LINES Proprietary Information

3.8 STRATIGRAPHIC COLUMN Proprietary Information

3.9 TIME VS DEPTH TABLES Proprietary Information**10344 Sam Houston Park Dr. Suite 300**  **Houston, Texas 77064 713.351.7900 [o] 713.351.7996 [f]**  **www.gemsinc.com**

**December 26, 2013 Project No. 1213-2338** 
**Deep Gulf Energy Companies 738 Highway 6 South,**  **Suite 800, Houston, Texas 77079** 

**Attention: Mr. Barry G. Hexton**

Site Clearance Letter Proposed Kodiak Site A Block 727 (OCS-G-24102) Mississippi Canyon Area Gulf of Mexico

**Deep Gulf Energy Companies (DGE) contracted Geoscie nce Earth & Marine Services (GEMS) to prepare**  **a Site Clearance Letter for the Proposed Kodiak Sit e A in Block 727 (OCS-G-24102), Mississippi Canyon**  **(MC) Area. This letter addresses specific seafloor and subsurface geologic conditions to the Top of S**  **alt, at approximately 3,269 ft below the mudline (bml).** 

**An area of authigenic carbonate outcrops and associ ated seep communities lies approximately 1,504 ft**  **southwest of the proposed wellsite. Internal variability of**  **sediment properties that could impact conductor jetting may be encountered within shallow mass-tran**  **sport deposits and the well is expected to intersec t**  **two faults at depth (approximately 2,076 ft and 2,6 96 ft bml). Offset wells also intercepted buried f**  **aults but encountered no problems along the faulted inter**  **vals. There is a low to high potential for encount ering**  **overpressured sands and a low potential for shallow gas accumulations within slope fan deposits (Blue,**  **Green, and Purple Units).**

**This letter provides details specific to the well l ocation, including: available data, Notice to Lesse**  **es (NTL) requirements, man-made features, and wellsite condi**  **tions.**

Proposed Well Location

**The Proposed Kodiak Site A surface location lies in the south-central portion of MC 727**  **(Figure MC 727-A-1). DGE plans to drill the well using a dynamically pos**  **itioned (DP) drillship or semi-submersible. Our assessment addresses the sea**  **floor conditions within a 2,000 ft radius around th e**  **proposed wellsite. The wellsite coordinates provid ed by DGE are as follows:** 

Proposed Kodiak Site A
Spheroid & Datum: Clarke 1866, NAD27 Projection: UTM Zone 16 North Line Reference Block Calls MC 727
**X: 1,052,150 ft Latitude: 28o 14’ 32.9302” N Inline 13738 6,710 ft FWL** 
**Y: 10,253,406 ft Longitude: 88o 49’ 39.1139” W Cros sline 13674 4,926 ft FSL** 

Available Data

**The following discussions are based on the studies performed by GEMS for BP America Production**  **Company (BP) in April, 2009 and DGE in November, 20 13. The 2009 study assessed the geologic and**  **geohazard conditions relevant to future development of the Tubular Bells/Kodiak Development Area**  **(Blocks 680 to 684, 724 to 728, and 768 to 772), GE MS, 2009. The 2013 assessment was a follow up** **Proposed Kodiak Site A Clearance Letter**

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 2 FORUM ENERGY TECHNOLOGIES, INC. **ROV investigation over a known chemosynthetic commu nity site (Site 03) in MC 727 (GEMS, 2013). BP**  **was the primary operator of the Tubular Bells/Kodia k Development Area before DGE acquired the Kodiak**  **Area (Blocks 727, 771, and vicinity).**

**The 2009 assessment was carried out using a suite o f datasets provided by BP. The pertinent**  **geophysical data include a reprocessed 3-D seismic data and high-resolution (HR) geophysical data**  **(Figure MC 727-A-1). The HR data was collected usi ng an autonomous underwater vehicle (AUV) and**  **comprises the following data; side-scan sonar, mult ibeam bathymetry, backscatter, and subbottom profil**  **er (SBP). The detailed data specifications of the sei**  **smic and HR data (AUV data) are provided in GEMS report no 0508-1497 (GEMS, 2009).** 

**DGE was provided the aforementioned AUV data and in terpretations from the reprocessed seismic**  **volume for this site clearance effort. GEMS import ed the seismic interpretations (horizons, faults, e**  **tc.) into a HR pre-stack time migration (PSTM) seismic v**  **olume provided by DGE (Figure MC 727-A-1). The representative seismic lines and other seismic data**  **examples presented in this letter were extracted f rom**  **DGE’s seismic volume. The following data were also incorporated in the assessment:** 

• **A suite of presentations and site clearance narrat ives developed by BP,** 

• **Well information (well logs and shallow hazards ob servation logs) from offset wells (DGE II’s Well**  **No. 1, and DGE II’s Well No. 2),**

• **Geotechnical investigation reports (AOA, 2009, FMM G 2009a/b, and FMMG, 2010),** 

• **ROV seafloor biological survey report by Dr. Carne y (Carney, 2008),** 

• **Checkshot survey from DGE II’s Well No. 1 – the ve locity information was used to generate a**  **sediment column velocity function. The velocity fu nction was used to convert the subsurface**  **horizon time to depth. The velocity function deriv ed is as follows:** 

**Depth (ft) = 3410.2x 6**  **- 10211x 5**  **+ 10379x 4**  **- 4370.4x 3**  **+ 1415.7x 2**  **+ 2460.1x - 0.0922 where x is two-way travel time below the mudline (b**  **ml) in seconds**

Figure MC 727-A-1 **. Seafloor Rendering of the Survey Area and Vicini ty, Mississippi Canyon Area,**  **Gulf of Mexico. The infrastructure shown on map was obtained from B**  **OEM database (BOEM, 2013a).** DEVIL’S TOWER MENSA MISSISSIPPI CANYON

AREA N

Mass-wasting Pathway

Erosional Remnants Chevron #1

DGE II #1 DGE II #2

3 miles **Proposed Kodiak Site A**
**Geotechnical Borings**
**3-D Reprocessed Seismic Data (source – BP)** 
**AUV Survey Area (source – BP)** 

**3-D HR PSTM Data (source – DGE)** 

**Existing Wells**

**Existing Platform**

**Pipelines**

**High-potential Archaelogical Area** 

**Chemosynthetic Area**

**Shallow Water Flow Area**

**Ordnance Disposal Area Proposed Kodiak Site A Clearance Letter** 

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 3 FORUM ENERGY TECHNOLOGIES, INC. Attachments

**The page-size maps, accompanying illustrations, and embedded figures were extracted from the available**  **geophysical data. Wellsite maps are centered on th e Proposed Kodiak Site A and are displayed at a**  **1 inch = 1,000 ft scale (1:12,000). The maps, illu strations, and figures are as follows:** 
**Map No. MC 727-A-1: Bathymetry Map Map No. MC 727-A-2: Seafloor Features Map**  **Map No. MC 727-A-3a: Side-Scan Sonar Mosaic Map No. MC 727-A-3b: Side-Scan Sonar Mosaic and Sea**  **floor Features Map No. MC 727-A-4: Geologic Features Map**  **Illustration MC 727-A-1: Portions of Inline 13738 and Crossline 13674 Showing Conditions Beneath**  **Proposed Kodiak Site A Illustration MC 727-A-2: Tophole Prognosis Chart,**  **Proposed Kodiak Site A, Mississippi Canyon, Block 727**  **Illustration MC 727-A-3: Correlation between Propo sed Kodiak Site A and Existing Wells**  **Figure MC 727-A-1: Seafloor Rendering of the Survey Area and Vicinity, Mississippi Canyon**  **Area, Gulf of Mexico Figure MC 727-A-2: Power Spectrum Analysis Curve,**  **Proposed Kodiak Site A Figure MC 727-A-3: Side-scan Sonar Mosaic Showing**  **Seep-related Features at Site 03 Figure MC 727-A-4: AUV Subbottom Profile Data Show**  **ing the Shallow Stratigraphic Unit Figure MC 727-A-5: Arbitrary HR Seismic Line Showi**  **ng the Deep Stratigraphic Unit**

NTL Requirements

**The following letter complies with the Bureau of Oc ean Energy Management (BOEM) Notice to Lessees**  **(NTL’s) 2008-G04, 2008-G05, and 2009-G40, (MMS, 200 8a, b and 2010). The requirements set forth in**  **NTL 2005-G07 are applicable because the Federal lea se block MC 727 is considered to be a high**  **probability archaeological block (MMS, 2005 and BOE M, 2011). In compliance with NTL 2005-G07, the**  **required archaeological assessment was performed fo r BP by C & C Technology Survey Services in 2007**  **(C & C, 2007).**

**According to NTL 2008-G05 (MMS, 2008b), 3-D seismic reflection data may be used for shallow hazard**  **assessments with approval from the BOEM, Gulf of Me xico Region. BP’s 3-D seismic data was**  **reprocessed using near offset traces to increase th e frequency content in the shallow section. The**  **reprocessed data in the vicinity of the proposed we ll location possesses a frequency content of 50 Hz**  **or more across the first second below the seabed (BOEM**  **, 2013b). Figure MC 727-A-2 shows the power spectrum analysis of DGE’s HR 3-D seismic volume.**  **The power spectrum curve was generated within a 500 ft radius of the intersection of the inline and**  **crossline at the proposed wellsite. The amplitude vs.**  **frequency spectrum generated by the SMT software wa s converted to power vs. frequency by squaring**  **the amplitude values as described by J. A. Coffeen, 1978.** 

Figure MC 727-A-2 **. Power Spectrum Analysis Curve, Proposed Kodiak Site A.**  **0 0.2**  **0.4 0.6**  **0.8 1**  **1.2**

**0 10 20 30 40 50 60 70 80**Power (Amp2)

Frequency (Hz) POWER SPECTRUM**Proposed Kodiak Site A Clearance Letter**

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 4 FORUM ENERGY TECHNOLOGIES, INC. Man-Made Features and Archaeological Assessment

**The surface location is clear of any wells, pipelin es, or platforms within a 2,000 ft radius from the**  **proposed wellsite. Numerous permitted pipelines ar e located in adjacent blocks MC 684, MC 728, and**  **MC 770-772 to the northeast, east, and south of the proposed wellsite, respectively**  **(Figure MC 727-A-1). There are existing wells and geotechnical borings within block MC 727; the close**  **st well (DGE II’s Well No. 2) lies approximately 2,597**  **ft north-northeast, while the closest boring (KCPT -04)**  **lies 1,901 ft east (Figure MC 727-A-1, Map MC 727-A -1). The details of the existing wells and borings**  **are shown in the tables below (AOA, 2009, FMMG 2009a/b,**  **and FMMG, 2010).**
Table 1. Existing Wells Within MC 727

Name Other Names X NAD27 (ft) Y

NAD27 (ft) Type/Status

Code *Dist./Direction

from Proposed Wellsite

**Chevron #1 OCS-G 13145,**  **MC727 Well No. 001 (API 60-817-40894-00)**  **1058460.06 10257338.04 Exploratory;**  ***PA 1.41 miles/NE** 

**DGE II’s Well #1**  **OCS-G 24107,**

**MC771 Well No. 001 ST00BP00 (API 60-817-41134-00)**  **1058326.96 10254723.09 Exploratory;**  ***PA 1.20 miles/ENE** 

**DGE II’s Well #1 S/T**  **OCS-G 24102,**

**MC727 Well No. 001 ST01BP00 (API 60-817-41134-01)**  **1058326.96 10254723.09 Exploratory;**  ***PA 1.20 miles/ENE** 

**DGE II’s Well #2**  **OCS-G 24102,**

**MC727 Well No. 002 ST00BP00 (API 60-817-41171-00)**  **1051997.74 10255998.12 Exploratory;**  ***TA 2,597 ft/NNE** 

***PA - Permanently Abandoned *TA – Temporary Aband** **oned *Dist - Distance**

Table 2. Borings Within MC 727

Name X

NAD27 (ft) Y

NAD27 (ft) Total

Depth, bml (ft) *Dist./Direction

from Proposed Wellsite Soil Description

**KSB-101 1048502 10257099 172 0.98 miles/NW Very soft to stiff olive**  **gray clay.**

**KSB-105 1056664 10254139 192 4,573 ft/ENE**  **Very soft to very stiff olive gray clay.**  **KSB-106 1058589 10249392 187 1.44 miles/SE**

**BH-2A 1048956 10251181 1,023 3,893 ft/SW Primarily clay. Blue**  **Unit comprise of clay, silts and sands.** 

**BH-2B 1049064 10251181 280 3,805 ft/SW Very soft to hard**  **olive gray clay with intermittent silt and**  **sand pockets. BH-2C 1049147 10251189 910 3,733 ft/SW** **Proposed Kodiak Site A Clearance Letter**

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 5 FORUM ENERGY TECHNOLOGIES, INC. Table 3. Seabed PCPT Within MC 727

Name X

NAD27 (ft) Y

NAD27 (ft) Total Depth

bml, (ft) *Dist./Direction

from Proposed Wellsite

**KCPT-01 1048499 10257057 ~134 0.98 miles/NW**

**KCPT-04 1054050 10253447 ~113 1,901 ft/E**

**KCPT-06 1061283 10254124 ~127 1.73 miles/E**

**KCPT-07 1057226 10251176 ~113 1.05 miles/SE**

Archaeological Assessment

**C & C delineated seven unidentified side-scan sonar contacts in MC 727; however, none of the contacts**  **appear to represent cultural resources (C & C, 2007 ), Table 4. The unidentified contacts were interpr**  **eted as debris from lease development activities or as g**  **eologic in origin. A 100 ft shallow hazard avoidan ce is**  **recommended for the contacts but none are recommend ed for archaeological avoidance or investigation.**  **The closest sonar contact (Number 19) lies approxim ately 4,830 ft east of Proposed Kodiak Site A.** 

Table 4. Sonar Contacts Located Within MC 727

No. Length

(ft) Width

(ft) Height

(ft) Shape X NAD27 (ft) Y

NAD27 (ft) Avoidance

Radius (ft)

**12 19.7 16.4 *NMH Irregular 1053003.54 10259122.00** **100**

**14 16.4 13.1 NMH Irregular 1059402.91 10257553.24 100** 

**15 16 20 NMH Irregular 1058663.87 10255660.00 100** 

**16 20 16 NMH Irregular 1058590.72 10255673.88 100** 

**17 16 10 NMH Irregular 1060126.04 10253228.31 100** 

**18 16 10 NMH Irregular 1058462.32 10253253.69 100** 

**19 16 10 NMH Irregular 1056958.71 10253861.67 100** 
***NMH – No measurable height**

Wellsite Conditions

**Proposed Kodiak Site A is expected to intersect two buried faults and many small undifferentiated faul**  **ts at depth. Within the suprasalt strata, there is a low**  **to high potential for encountering overpressured s ands**  **and a low potential for shallow gas accumulations w ithin slope fan deposits.** 
Water Depth and Seafloor Conditions

**The water depth at the proposed surface location is approximately -4,818 ft and the seafloor slopes**  **southeast at approximately 2° (Map MC 727-A-1). Sl ope instability conditions are not expected at the**  **proposed wellsite.**
**The Proposed Kodiak Site A lies along a relatively smooth low-lying valley, less than a mile from an**  **escarpment in the southeast (Map MC 727-A-2). The valleys were preferred sediment pathways for**  **mass-wasting processes in the recent geologic past (Figure MC 727-A-1). Major mass-wasting**  **processes have ceased since the last major sea-leve l lowstand. The near-surface stratigraphy consists**  **mostly of well-layered sediments (up to 60 ft thick ). The low sonar reflectivity suggests that the se**  **abed is draped by soft clays (Map MC 727-A-3a).** **Proposed Kodiak Site A Clearance Letter**

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 6 FORUM ENERGY TECHNOLOGIES, INC. Deepwater Benthic Communities

**The proposed wellsite lies near an identified chemo synthetic community. The seep community (Site 03)**  **was identified during an ROV investigation conducte d in 2008 by Oceaneering for BP. This ROV survey**  **indicated that the area was partially populated by tubeworms and mussels, estimating 11.2% of the**  **expulsion site coverage (Carney, 2008, GEMS, 2009), Figure MC 727-A-3. At that time, Site 03 was not**  **classified as a high density population area. Also at that time, the Site 03 expulsion area boundary w**  **as determined to be mapped for BP Geohazards report (G**  **EMS Report No. 0508-1497, GEMS, 2009).**

**After discussions and consultations with BOEM, a su bsequent follow-up ROV survey investigation over**  **Site 03 was conducted in 2013 to determine if any s ignificant changes in the chemosynthetic community**  **had occurred since 2008. This survey confirmed limi ted seep community coverage at the expulsion zone**  **(GEMS, 2013), Map MC 727-A-3b and Figure MC 727-A-3 . The 2013 ROV investigation was conducted**  **by Surf Subsea and GEMS.**

**BOEM has reviewed the ROV videos from 2008 and 2013 , and have determined that the identified Site**  **03 chemosynthetic community is “at the lower end of what may be judged to be considered as high**  **density communities” (Dave Moran, personal communic ation, December 03, 2013). It was also**  **determined that the areal extent of the defined hig h density deepwater benthic community is represente**  **d by a polygon defined as “Area of closely spaced, ro**  **cky, authigenic carbonate outcrops, chemosynthetic organisms (predominately mussels and tubeworms) exi**  **st at and near some outcrops” (Map MC 727-A-3b,**  **GEMS, 2013).**

**A 1,500 ft avoidance buffer zone (as measured from the polygon defined above) has been permitted**  **around this specific Site 03 seep community instead of the customary 2,000 ft avoidance zone specified**  **in BOEM’s NTL No. 2009-G40 (MMS, 2010).**

**The Proposed Kodiak Site A lies outside the 1,500 f t avoidance zone at approximately 1,504 ft northeas**  **t of the Site 03 seep community polygon boundary as d**  **efined above.**

**Other expulsion features are located north and sout heast of the proposed wellsite; however, there are**  **no apparent geophysical indicators at these sites to s**  **uggest conditions capable of supporting significant high-density deepwater benthic communities (Maps MC**  **727-A-2 and MC 727-A-3a), GEMS, 2009.**

Figure MC 727-A-3 **. Side-scan Sonar Mosaic Showing Seep-related Feat ures at Site 03.**  **The chemosynthetic organisms (within the green poly gon) are predominantly mussels and tubeworms.**  **Source - *i (GEMS, 2009); *iii and *iv (GEMS, 2013)**

**.** Proposed Kodiak Site A N

*i

*ii
*iii

*iv

***i - 1,500 ft avoidance** ***ii - Expulsion feature** ***iii- Seafloor depression surrounding outcrops**

**where bacteria cover and mussels exist** ***iv - Area of closely spaced, rocky, authigenic carbonate outcrops. Chemosynthetic**  **organisms exist at and near some outcrops** Site 03

1,000 ft **G - prior 2009 BP SEP Control # S-07315 Approval**  **I - prior 2010 BP SEP Control # S-07369 Approval**  G

I**Proposed Kodiak Site A Clearance Letter**

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 9 FORUM ENERGY TECHNOLOGIES, INC. **fine-grained sediments from the Seafloor to 249 ft bml and 439 ft to 1,118 ft bml. There is a low pot**  **ential for encountering minor accumulations of gas in the**  **Blue Unit (249 ft to 439 ft bml), and from the Top of**  **the Green Unit to the Top of Salt (1,118 ft to 3,26 9 ft bml).** 

Hydrates. **A bottom simulating reflector (BSR) was identified approximately 1,885 ft southwest of the**  **proposed wellsite from 794 ft to 1,359 ft bml (GEMS , 2009). The BSR marks the Base of the Hydrate**  **Stability Zone (BHSZ) and represents the acoustic i mpedance contrast between potentially**  **hydrate-bearing sediments and free gas bearing sedi ments beneath the BHSZ. The proposed wellsite**  **lies outside the mapped BSR extent (Map MC 727-A-4)**

**. There was no evidence of encountering shallow gas h**  **ydrates while drilling the riserless section at DGE II’s Well No. 1 and DGE II’s Well No. 2. The w**  **ireline log data at BH-2A also showed no evidence o f**  **gas hydrate being present in any significant quanti ties (AOA, 2009). Consequently, we consider that**  **there is a negligible potential for encountering hy drates at Proposed Kodiak Site A.** 

Shallow Water Flow. **Shallow water flow (SWF) occurrences within block M C 727 were observed at**  **Chevron #1 and DGE II’s No. 1 wells. Overpressured sands were encountered within the Green Unit at**  **Chevron #1 and from the top of the Purple Unit to t he 22-inch casing depth at DGE II’s Well No. 1**  **(Illustration MC 727-A-3). Severe SWF was observed at 1,499 ft bml while drilling with seawater at**  **Chevron #1. Low SWF was observed at DGE II’s Well No. 1 at 2,122 ft bml, and intermittently to the**  **base of the 26-inch hole at 3,089 ft bml. The 26-i nch hole was drilled with water based mud. SWF was**  **not observed at DGE II’s Well No. 2, likely due to better well control measures. Within the Blue Unit**  **at BH-2A, locally higher pressures were measured in th**  **in sand/silt bands and possible indication of SWF was noted in the temperature log (AOA, 2009). Howe**  **ver, no SWF was observed within the Blue Unit at the boreholes and the existing wells.** 

**The potential for SWF at the proposed wellsite vari es from negligible to high based on the seismic fac**  **ies correlation between the proposed wellsite and exist**  **ing wells (Illustration MC 727-A-3). There is a hi gh**  **potential for SWF within the Green Unit (1,118 ft t o 2,028 ft bml); a moderate potential within the Pu**  **rple Unit (2,547 ft to 2,751 ft bml); a low potential wi**  **thin the Blue Unit (249 ft to 439 ft bml), below th e Green**  **Unit (2,028 ft to 2,547 ft bml), and below the Purp le Unit (2,751 ft to 3,269 ft bml); and a negligibl**  **e potential in clay-rich stratigraphy between the Sea**  **floor to 249 ft bml and 439 ft to 1,118 ft bml.**

Findings and Recommendations

**An area of authigenic carbonate outcrops and associ ated seep communities was identified approximately**  **1,504 ft southwest of the proposed wellsite. Inter nal variability of sediment properties that could i**  **mpact conductor jetting may be encountered within shallow**  **mass-transport deposits between the Seafloor and 249 ft bml. Two sub-regional SWF units (the Blue U**  **nit and Green Unit) occur at 249 ft bml and 1,118 f t**  **bml respectively. A third SWF prone unit (Purple U nit) occurs at 2,547 ft bml. Caution is recommende**  **d when drilling through these sediment units, and whe**  **n intersecting buried faults at approximately 2,076 ft**  **and 2,696 ft bml. Proposed Kodiak Site A Clearance Letter** 

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 10 FORUM ENERGY TECHNOLOGIES, INC. Closing

**We appreciate the opportunity to be of service to D eep Gulf Energy Companies, and look forward to**  **working together on future projects.**

**Sincerely,**

GEOSCIENCE EARTH & MARINE SERVICES

**Oluwayomi Oyedele Daniel Lanier Geoscientist**  **Director – Geoscience Earth & Marine Services**

**Erin Williams Janes Project Manager/Senior Geoscientist** 

**Attachments (5 Maps and 3 Illustrations)**

**Distribution: Mr. Barry G. Hexton, Deep Gulf Energy Companies (6 copies)** 

REFERENCES

**AOA Geophysics Inc., 2009, Interpretation of wireli ne logging data and integration with other relevant**  **data, Kodiak geotechnical investigation, Mississippi Canyon, Gul**  **f of Mexico: Report prepared for BP America Inc., R eport No.**  **4041-BP-GOM-KOD-01.**

**Bureau of Ocean Energy Management, 2013a, ASCII Dat a Files, published on the BOEM Gulf of Mexico Regio**  **n Homepage, <http://www.gomr.boem.gov/homepg/pubinfo/**  **freeasci/freedesc.html>, accessed December, 2013.**

**Bureau of Ocean Energy Management, 2013b, Explorati on Plan Control # S-07369, published on the BOEM Gu**  **lf of Mexico Region Homepage, <**  **http://www.data.boem.gov/PI/PDFImages/PLANS/30/3073 9.pdf>, accessed June,**  **2013.**

**Bureau of Ocean Energy Management, 2011, Notice to lessees and operators (NTL) of federal oil and gas**  **leases and pipeline right-of-way (ROW) holders on the oute**  **r continental shelf (OCS), revisions to the list of OCS lease**  **blocks requiring archaeological resource surveys an d reports: U.S. Departments of the Interior, Bureau**  **of Ocean Energy Management, Bureau of Safety and Environment**  **al Enforcement, Gulf of Mexico OCS Region (GOMR), N TL**  **2011-JOINT-G01. Effective Date December 29, 2011.**

**Carney, R.S., 2008, Summary of seafloor fauna obser ved during the Tubular Bells and Kodiak appraisal a**  **rea ROV seafloor biological survey: Report prepared for BP**  **America Inc., Report No. TBEL1-10GO-RP-000013.**

**C&C Technologies Survey Services, (C&C), 2007, Arch aeological Assessment Report, Block 727 & Vicinity,**  **Mississippi Canyon Area: Report prepared for BP America Inc., J**  **ob no. 072456-073011.**

**Coffeen, J. A., 1978, Seismic Exploration Fundament als: Tulsa, the Petroleum Publishing Co., p. 125.** 

**Fugro McClelland Marine Geosciences, Inc., (FMMG), 2009a, Deepwater geotechnical investigation, Kodiak**  **Prospect SPAR development, Blocks 726, 727, 728, 770 & 771,**  **Mississippi Canyon Area, Gulf of Mexico: Report pre pared for**  **BP America Inc., Report No. 0201-6584-1, volume I. Proposed Kodiak Site A Clearance Letter** 

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 11 FORUM ENERGY TECHNOLOGIES, INC. **Fugro McClelland Marine Geosciences, Inc., (FMMG), 2009b, Shallow water flow investigation, Kodiak Pro**  **spect, Blocks 727 & 771, Mississippi Canyon Area, Gulf of**  **Mexico: Report prepared for BP America Inc., Report No. 0201-**  **6584-2, volumes I, II, & III.**

**Fugro McClelland Marine Geosciences, Inc., (FMMG), 2010, Deepwater geotechnical investigation, Kodiak**  **Prospect SPAR development, Blocks 726, 727, 728, 770 & 771,**  **Mississippi Canyon Area, Gulf of Mexico: Report pre pared for**  **BP America Inc., Report No. 0201-6584-1, volume II.**

**Geoscience Earth & Marine Services, (GEMS), 2009, T ubular Bells/Kodiak development project, geologic a**  **nd stratigraphic assessment, Blocks 680 to 684, 724 to**  **728, & 768 to 772, Mississippi Canyon Area, Gulf o f Mexico,**  **Project No. 0508-1497.**

**Geoscience Earth & Marine Services, (GEMS), 2013, S eafloor verification study using ROV data, Block 72**  **7, Mississippi Canyon Area, Gulf of Mexico, Project No**  **. 0713-2273.**

**Minerals Management Service, 2005, Notice to lessee s and operators of federal oil, gas, and sulphur le**  **ases and pipeline right-of-way holders in the outer continen**  **tal shelf, Gulf of Mexico OCS region, Archaeologica l resource**  **surveys and reports: U. S. Department of the Inter ior, Minerals Management Service, Gulf of Mexico, N**  **TL 2005-G07.**

**Minerals Management Service, 2008a, Notice to lesse es and operators of federal oil, gas, and sulphur l**  **eases and pipeline right-of-way holders in the outer continen**  **tal shelf, Gulf of Mexico OCS region, information r equirements for**  **exploration plans and development operations coordi nation documents: U. S. Department of the Interior,**  **Minerals Management Service, Gulf of Mexico, NTL 2008-G04.** 

**Minerals Management Service, 2008b, Notice to lesse es and operators of federal oil, gas, and sulphur l**  **eases and pipeline right-of-way holders in the outer continen**  **tal shelf, Gulf of Mexico OCS region, shallow hazar ds requirements:**  **U. S. Department of the Interior, Minerals Manageme nt Service, Gulf of Mexico, NTL 2008-G05.** 

**Minerals Management Service, 2010, Notice to lessee s and operators of federal oil and gas leases in th**  **e outer continental shelf, Gulf of Mexico OCS region, deepw**  **ater benthic communities: U. S. Department of the I nterior,**  **Minerals Management Service, Gulf of Mexico, NTL 20 09-G40. Effective Date January 27, 2010.** **10344 Sam Houston Park Dr. Suite 300**  **Houston, Texas 77064 713.351.7900 [o] 713.351.7996 [f]**  **www.gemsinc.com**

**December 26, 2013 Project No. 1213-2338** 
**Deep Gulf Energy Companies 738 Highway 6 South,**  **Suite 800, Houston, Texas 77079** 

**Attention: Mr. Barry G. Hexton**

Site Clearance Letter Proposed Kodiak Site B Block 727 (OCS-G-24102) Mississippi Canyon Area Gulf of Mexico

**Deep Gulf Energy Companies (DGE) contracted Geoscie nce Earth & Marine Services (GEMS) to prepare**  **a Site Clearance Letter for the Proposed Kodiak Sit e B in Block 727 (OCS-G-24102), Mississippi Canyon**  **(MC) Area. This letter addresses specific seafloor and subsurface geologic conditions to the Top of S**  **alt, at approximately 3,210 ft below the mudline (bml).** 

**An area of authigenic carbonate outcrops and associ ated seep communities lies approximately 1,598 ft**  **southwest of the proposed wellsite. Internal varia bility of sediment properties that could impact con**  **ductor jetting may be encountered within shallow mass-tran**  **sport deposits and the well is expected to intersec t**  **two faults at depth (approximately 1,742 ft and 2,4 42 ft bml). Offset wells also intercepted buried f**  **aults but encountered no problems along the faulted inter**  **vals. There is a low to high potential for encount ering**  **overpressured sands and a low potential for shallow gas accumulations within slope fan deposits (Blue,**  **Green, and Purple Units).**

**This letter provides details specific to the well l ocation, including: available data, Notice to Lesse**  **es (NTL) requirements, man-made features, and wellsite condi**  **tions.**

Proposed Well Location

**The Proposed Kodiak Site B surface location lies in the south-central portion of MC 727**  **(Figure MC 727-B-1). DGE plans to drill the well u sing a dynamically positioned (DP) drillship or**  **semi-submersible. Our assessment addresses the sea floor conditions within a 2,000 ft radius around th**  **e proposed wellsite. The wellsite coordinates provid**  **ed by DGE are as follows:**

Proposed Kodiak Site B
Spheroid & Datum: Clarke 1866, NAD27 Projection: UTM Zone 16 North Line Reference Block Calls MC 727
**X: 1,052,310 ft Latitude: 28o 14’ 32.9548” N Inline 13740 6,870 ft FWL** 
**Y: 10,253,406 ft Longitude: 88o 49’ 37.3251” W Cros sline 13671 4,926 ft FSL** 

Available Data

**The following discussions are based on the studies performed by GEMS for BP America Production**  **Company (BP) in April, 2009 and DGE in November, 20 13. The 2009 study assessed the geologic and**  **geohazard conditions relevant to future development of the Tubular Bells/Kodiak Development Area**  **(Blocks 680 to 684, 724 to 728, and 768 to 772), GE MS, 2009. The 2013 assessment was a follow up** **Proposed Kodiak Site B Clearance Letter**

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 2 FORUM ENERGY TECHNOLOGIES, INC. **ROV investigation over a known chemosynthetic commu nity site (Site 03) in MC 727 (GEMS, 2013). BP**  **was the primary operator of the Tubular Bells/Kodia k Development Area before DGE acquired the Kodiak**  **Area (Blocks 727, 771, and vicinity).**

**The 2009 assessment was carried out using a suite o f datasets provided by BP. The pertinent**  **geophysical data include a reprocessed 3-D seismic data and high-resolution (HR) geophysical data**  **(Figure MC 727-B-1). The HR data was collected usi ng an autonomous underwater vehicle (AUV) and**  **comprises the following data; side-scan sonar, mult ibeam bathymetry, backscatter, and subbottom profil**  **er (SBP). The detailed data specifications of the sei**  **smic and HR data (AUV data) are provided in GEMS report no 0508-1497 (GEMS, 2009).** 

**DGE was provided the aforementioned AUV data and in terpretations from the reprocessed seismic**  **volume for this site clearance effort. GEMS import ed the seismic interpretations (horizons, faults, e**  **tc.) into a HR pre-stack time migration (PSTM) seismic v**  **olume provided by DGE (Figure MC 727-B-1). The representative seismic lines and other seismic data**  **examples presented in this letter were extracted f rom**  **DGE’s seismic volume. The following data were also incorporated in the assessment:** 

• **A suite of presentations and site clearance narrat ives developed by BP,** 

• **Well information (well logs and shallow hazards ob servation logs) from offset wells (DGE II’s Well**  **No. 1, and DGE II’s Well No. 2),**

• **Geotechnical investigation reports (AOA, 2009, FMM G 2009a/b, and FMMG, 2010),** 

• **ROV seafloor biological survey report by Dr. Carne y (Carney, 2008),** 

• **Checkshot survey from DGE II’s Well No. 1 – the ve locity information was used to generate a**  **sediment column velocity function. The velocity fu nction was used to convert the subsurface**  **horizon time to depth. The velocity function deriv ed is as follows:** 

**Depth (ft) = 3410.2x 6**  **- 10211x 5**  **+ 10379x 4**  **- 4370.4x 3**  **+ 1415.7x 2**  **+ 2460.1x - 0.0922 where x is two-way travel time below the mudline (b**  **ml) in seconds**

Figure MC 727-B-1 **. Seafloor Rendering of the Survey Area and Vicini ty, Mississippi Canyon Area,**  **Gulf of Mexico. The infrastructure shown on map was obtained from B**  **OEM database (BOEM, 2013a).** DEVIL’S TOWER MENSA MISSISSIPPI CANYON

AREA N

Chevron #1

DGE II #1 DGE II #2

**Proposed Kodiak Site B**
**Geotechnical Borings**
**3-D Reprocessed Seismic Data (source – BP)** 
**AUV Survey Area (source – BP)** 

**3-D HR PSTM Data (source – DGE)** 

**Existing Wells**

**Existing Platform**

**Pipelines**

**High-potential Archaelogical Area** 

**Chemosynthetic Area**

**Shallow Water Flow Area**

**Ordnance Disposal Area** 3 miles Mass-wasting Pathway

Erosional Remnants**Proposed Kodiak Site B Clearance Letter**

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 3 FORUM ENERGY TECHNOLOGIES, INC. Attachments

**The page-size maps, accompanying illustrations, and embedded figures were extracted from the available**  **geophysical data. Wellsite maps are centered on th e Proposed Kodiak Site B and are displayed at a**  **1 inch = 1,000 ft scale (1:12,000). The maps, illu strations, and figures are as follows:** 
**Map No. MC 727-B-1: Bathymetry Map Map No. MC 727-B-2: Seafloor Features Map**  **Map No. MC 727-B-3a: Side-Scan Sonar Mosaic Map No. MC 727-A-3b: Side-Scan Sonar Mosaic and Sea**  **floor Features Map No. MC 727-B-4: Geologic Features Map**  **Illustration MC 727-B-1: Portions of Inline 13740 and Crossline 13671 Showing Conditions Beneath**  **Proposed Kodiak Site B Illustration MC 727-B-2: Tophole Prognosis Chart,**  **Proposed Kodiak Site B, Mississippi Canyon, Block 727**  **Illustration MC 727-B-3: Correlation between Propo sed Kodiak Site B and Existing Wells**  **Figure MC 727-B-1: Seafloor Rendering of the Survey Area and Vicinity, Mississippi Canyon**  **Area, Gulf of Mexico Figure MC 727-B-2: Power Spectrum Analysis Curve,**  **Proposed Kodiak Site B Figure MC 727-B-3:**  **Side-scan Sonar Mosaic Showing Seep-related Feature s at Site 03**  **Figure MC 727-B-4: AUV Subbottom Profile Data Show ing the Shallow Stratigraphic Unit**  **Figure MC 727-B-5: Arbitrary HR Seismic Line Showi ng the Deep Stratigraphic Unit** 

NTL Requirements

**The following letter complies with the Bureau of Oc ean Energy Management (BOEM) Notice to Lessees**  **(NTL’s) 2008-G04, 2008-G05, and 2009-G40, (MMS, 200 8a, b and 2010). The requirements set forth in**  **NTL 2005-G07 are applicable because the Federal lea se block MC 727 is considered to be a high**  **probability archaeological block (MMS, 2005 and BOE M, 2011). In compliance with NTL 2005-G07, the**  **required archaeological assessment was performed fo r BP by C & C Technology Survey Services in 2007**  **(C & C, 2007).**

**According to NTL 2008-G05 (MMS, 2008b), 3-D seismic reflection data may be used for shallow hazard**  **assessments with approval from the BOEM, Gulf of Me xico Region. BP’s 3-D seismic data was**  **reprocessed using near offset traces to increase th e frequency content in the shallow section. The**  **reprocessed data in the vicinity of the proposed we ll location possesses a frequency content of 50 Hz**  **or more across the first second below the seabed (BOEM**  **, 2013b). Figure MC 727-B-2 shows the power spectrum analysis of DGE’s HR 3-D seismic volume.**  **The power spectrum curve was generated within a 500 ft radius of the intersection of the inline and**  **crossline at the proposed wellsite. The amplitude vs.**  **frequency spectrum generated by the SMT software wa s converted to power vs. frequency by squaring**  **the amplitude values as described by J. A. Coffeen, 1978.** 

Figure MC 727-B-2 **. Power Spectrum Analysis Curve, Proposed Kodiak**  **Site B. 0**  **0.2 0.4**  **0.6 0.8**  **1 1.2** 

**0 10 20 30 40 50 60 70 80**Power (Amp2)

Frequency (Hz) POWER SPECTRUM**Proposed Kodiak Site B Clearance Letter**

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 4 FORUM ENERGY TECHNOLOGIES, INC. Man-Made Features and Archaeological Assessment

**The surface location is clear of any wells, pipelin es, or platforms within a 2,000 ft radius from the**  **proposed wellsite. Numerous permitted pipelines ar e located in adjacent blocks MC 684, MC 728, and**  **MC 770-772 to the northeast, east, and south of the proposed wellsite, respectively**  **(Figure MC 727-B-1). There are existing wells and geotechnical borings within block MC 727; the close**  **st well (DGE II’s Well No. 2) lies approximately 2,611**  **ft north-northeast, while the closest boring (KCPT -04)**  **lies 1,741 ft east (Figure MC 727-B-1, Map MC 727-B -1). The details of the existing wells and borings**  **are shown in the tables below (AOA, 2009, FMMG 2009a/b,**  **and FMMG, 2010).**
Table 1. Existing Wells Within MC 727

Name Other Names X NAD27 (ft) Y

NAD27 (ft) Type/Status

Code *Dist./Direction

from Proposed Wellsite

**Chevron #1 OCS-G 13145,**  **MC727 Well No. 001 (API 60-817-40894-00)**  **1058460.06 10257338.04 Exploratory;**  ***PA 1.38 miles/NE** 

**DGE II’s Well #1**  **OCS-G 24107,**

**MC771 Well No. 001 ST00BP00 (API 60-817-41134-00)**  **1058326.96 10254723.09 Exploratory;**  ***PA 1.17 miles/ENE** 

**DGE II’s Well #1 S/T**  **OCS-G 24102,**

**MC727 Well No. 001 ST01BP00 (API 60-817-41134-01)**  **1058326.96 10254723.09 Exploratory;**  ***PA 1.17 miles/ENE** 

**DGE II’s Well #2**  **OCS-G 24102,**

**MC727 Well No. 002 ST00BP00 (API 60-817-41171-00)**  **1051997.74 10255998.12 Exploratory;**  ***TA 2,611 ft/NNE** 

***PA - Permanently Abandoned *TA – Temporary Aband** **oned *Dist - Distance**

Table 2. Borings Within MC 727

Name X

NAD27 (ft) Y

NAD27 (ft) Total

Depth, bml (ft) *Dist./Direction

from Proposed Wellsite Soil Description

**KSB-101 1048502 10257099 172 1.01 miles/NW Very soft to stiff olive**  **gray clay.**

**KSB-105 1056664 10254139 192 4,415 ft/ENE**  **Very soft to very stiff olive gray clay.**  **KSB-106 1058589 10249392 187 1.41 miles/SE**

**BH-2A 1048956 10251181 1,023 4,025 ft/SW Primarily clay. Blue**  **Unit comprise of clay, silts and sands.** 

**BH-2B 1049064 10251181 280 3,935 ft/SW Very soft to hard**  **olive gray clay with intermittent silt and**  **sand pockets. BH-2C 1049147 10251189 910 3,863 ft/SW** **Proposed Kodiak Site B Clearance Letter**

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 5 FORUM ENERGY TECHNOLOGIES, INC. Table 3. Seabed PCPT Within MC 727

Name X

NAD27 (ft) Y

NAD27 (ft) Total Depth

bml, (ft) *Dist./Direction

from Proposed Wellsite

**KCPT-01 1048499 10257057 ~134 1 mile/NW**

**KCPT-04 1054050 10253447 ~113 1,741 ft/E**

**KCPT-06 1061283 10254124 ~127 1.71 miles/E**

**KCPT-07 1057226 10251176 ~113 1.02 miles/SE**

Archaeological Assessment

**C & C delineated seven unidentified side-scan sonar contacts in MC 727; however, none of the contacts**  **appear to represent cultural resources (C & C, 2007 ), Table 4. The unidentified contacts were interpr**  **eted as debris from lease development activities or as g**  **eologic in origin. A 100 ft shallow hazard avoidan ce is**  **recommended for the contacts but none are recommend ed for archaeological avoidance or investigation.**  **The closest sonar contact (Number 19) lies approxim ately 4,671 ft east of Proposed Kodiak Site B.** 

Table 4. Sonar Contacts Located Within MC 727

No. Length

(ft) Width

(ft) Height

(ft) Shape X NAD27 (ft) Y

NAD27 (ft) Avoidance

Radius (ft)

**12 19.7 16.4 *NMH Irregular 1053003.54 10259122.00** **100**

**14 16.4 13.1 NMH Irregular 1059402.91 10257553.24 100** 

**15 16 20 NMH Irregular 1058663.87 10255660.00 100** 

**16 20 16 NMH Irregular 1058590.72 10255673.88 100** 

**17 16 10 NMH Irregular 1060126.04 10253228.31 100** 

**18 16 10 NMH Irregular 1058462.32 10253253.69 100** 

**19 16 10 NMH Irregular 1056958.71 10253861.67 100** 
***NMH – No measurable height**

Wellsite Conditions

**Proposed Kodiak Site B is expected to intersect two buried faults and many small undifferentiated faul**  **ts at depth. Within the suprasalt strata, there is a low**  **to high potential for encountering overpressured s ands**  **and a low potential for shallow gas accumulations w ithin slope fan deposits.** 
Water Depth and Seafloor Conditions

**The water depth at the proposed surface location is approximately -4,823 ft and the seafloor slopes**  **southeast at approximately 4° (Map MC 727-B-1). Sl ope instability conditions are not expected at the**  **proposed wellsite.**
**The Proposed Kodiak Site B lies along a relatively smooth low-lying valley, less than a mile from an**  **escarpment in the southeast (Map MC 727-B-2). The valleys were preferred sediment pathways for**  **mass-wasting processes in the recent geologic past (Figure MC 727-B-1). Major mass-wasting**  **processes have ceased since the last major sea-leve l lowstand. The near-surface stratigraphy consists**  **mostly of well-layered sediments (up to 60 ft thick ). The low sonar reflectivity suggests that the se**  **abed is draped by soft clays (Map MC 727-B-3a).** **Proposed Kodiak Site B Clearance Letter**

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 6 FORUM ENERGY TECHNOLOGIES, INC. Deepwater Benthic Communities

**The proposed wellsite lies near an identified chemo synthetic community. The seep community (Site 03)**  **was identified during an ROV investigation conducte d in 2008 by Oceaneering for BP. This ROV survey**  **indicated that the area was partially populated by tubeworms and mussels, estimating 11.2% of the**  **expulsion site coverage (Carney, 2008, GEMS, 2009), Figure MC 727-B-3. At that time, Site 03 was not**  **classified as a high density population area. Also at that time, the Site 03 expulsion area boundary w**  **as determined to be mapped for BP Geohazards report (G**  **EMS Report No. 0508-1497, GEMS, 2009).**

**After discussions and consultations with BOEM, a su bsequent follow-up ROV survey investigation over**  **Site 03 was conducted in 2013 to determine if any s ignificant changes in the chemosynthetic community**  **had occurred since 2008. This survey confirmed limi ted seep community coverage at the expulsion zone**  **(GEMS, 2013), Map MC 727-B-3b and Figure MC 727-B-3 . The 2013 ROV investigation was conducted**  **by Surf Subsea and GEMS.**

**BOEM has reviewed the ROV videos from 2008 and 2013 , and have determined that the identified Site**  **03 chemosynthetic community is “at the lower end of what may be judged to be considered as high**  **density communities” (Dave Moran, personal communic ation, December 03, 2013). It was also**  **determined that the areal extent of the defined hig h density deepwater benthic community is represente**  **d by a polygon defined as “Area of closely spaced, ro**  **cky, authigenic carbonate outcrops, chemosynthetic organisms (predominately mussels and tubeworms) exi**  **st at and near some outcrops” (Map MC 727-B-3b,**  **GEMS, 2013).**

**A 1,500 ft avoidance buffer zone (as measured from the polygon defined above) has been permitted**  **around this specific Site 03 seep community instead of the customary 2,000 ft avoidance zone specified**  **in BOEM’s NTL No. 2009-G40 (MMS, 2010).**

**The Proposed Kodiak Site B lies outside the 1,500 f t avoidance zone at approximately 1,598 ft northeas**  **t of the Site 03 seep community polygon boundary as d**  **efined above.**

**Other expulsion features are located north and sout heast of the proposed wellsite; however, there are**  **no apparent geophysical indicators at these sites to s**  **uggest conditions capable of supporting significant high-density deepwater benthic communities (Maps MC**  **727-B-2 and MC 727-B-3a), GEMS, 2009.**

Figure MC 727-B-3 **. Side-scan Sonar Mosaic Showing Seep-related Feat ures at Site 03.**  **The chemosynthetic organisms (within the green poly gon) are predominantly mussels and tubeworms.**  **Source - *i (GEMS, 2009); *iii and *iv (GEMS, 2013)**

**.** Proposed Kodiak Site B N

*i

*ii *iii

*iv

***i - 1,500 ft avoidance** ***ii - Expulsion feature** ***iii- Seafloor depression surrounding outcrops**

**where bacteria cover and mussels exist** ***iv - Area of closely spaced, rocky, authigenic carbonate outcrops. Chemosynthetic**  **organisms exist at and near some outcrops** 1,000 ft **G - prior 2009 BP SEP Control # S-07315 Approval**  **I - prior 2010 BP SEP Control # S-07369 Approval**  Site 03 G

I**Proposed Kodiak Site B Clearance Letter**

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 9 FORUM ENERGY TECHNOLOGIES, INC. **fine-grained sediments from the Seafloor to 246 ft bml and 437 ft to 1,118 ft bml. There is a low pot**  **ential for encountering minor accumulations of gas in the**  **Blue Unit (246 ft to 437 ft bml), and from the Top of**  **the Green Unit to the Top of Salt (1,118 ft to 3,21 0 ft bml).** 

Hydrates. **A bottom simulating reflector (BSR) was identified approximately 1,960 ft southwest of the**  **proposed wellsite from 794 ft to 1,359 ft bml (GEMS , 2009). The BSR marks the Base of the Hydrate**  **Stability Zone (BHSZ) and represents the acoustic i mpedance contrast between potentially**  **hydrate-bearing sediments and free gas bearing sedi ments beneath the BHSZ. The proposed wellsite**  **lies outside the mapped BSR extent (Map MC 727-B-4)**

**. There was no evidence of encountering shallow gas h**  **ydrates while drilling the riserless section at DGE II’s Well No. 1 and DGE II’s Well No. 2. The w**  **ireline log data at BH-2A also showed no evidence o f**  **gas hydrate being present in any significant quanti ties (AOA, 2009). Consequently, we consider that**  **there is a negligible potential for encountering hy drates at Proposed Kodiak Site B.** 

Shallow Water Flow. **Shallow water flow (SWF) occurrences within block M C 727 were observed at**  **Chevron #1 and DGE II’s No. 1 wells. Overpressured sands were encountered within the Green Unit at**  **Chevron #1 and from the top of the Purple Unit to t he 22-inch casing depth at DGE II’s Well No. 1**  **(Illustration MC 727-B-3). Severe SWF was observed at 1,499 ft bml while drilling with seawater at**  **Chevron #1. Low SWF was observed at DGE II’s Well No. 1 at 2,122 ft bml, and intermittently to the**  **base of the 26-inch hole at 3,089 ft bml. The 26-i nch hole was drilled with water based mud. SWF was**  **not observed at DGE II’s Well No. 2, likely due to better well control measures. Within the Blue Unit**  **at BH-2A, locally higher pressures were measured in th**  **in sand/silt bands and possible indication of SWF was noted in the temperature log (AOA, 2009). Howe**  **ver, no SWF was observed within the Blue Unit at the boreholes and the existing wells.** 

**The potential for SWF at the proposed wellsite vari es from negligible to high based on the seismic fac**  **ies correlation between the proposed wellsite and exist**  **ing wells (Illustration MC 727-B-3). There is a hi gh**  **potential for SWF within the Green Unit (1,118 ft t o 1,932 ft bml); a moderate potential within the Pu**  **rple Unit (2,500 ft to 2,718 ft bml); a low potential wi**  **thin the Blue Unit (246 ft to 437 ft bml), below th e Green**  **Unit (1,932 ft to 2,500 ft bml), and below the Purp le Unit (2,718 ft to 3,210 ft bml); and a negligibl**  **e potential in clay-rich stratigraphy between the Sea**  **floor to 246 ft bml and 437 ft to 1,118 ft bml.**

Findings and Recommendations

**An area of authigenic carbonate outcrops and associ ated seep communities was identified approximately**  **1,598 ft southwest of the proposed wellsite. Inter nal variability of sediment properties that could i**  **mpact conductor jetting may be encountered within shallow**  **mass-transport deposits between the Seafloor and 246 ft bml. Two sub-regional SWF units (the Blue U**  **nit and Green Unit) occur at 246 ft bml and 1,118 f t**  **bml respectively. A third SWF prone unit (Purple U nit) occurs at 2,500 ft bml. Caution is recommende**  **d when drilling through these sediment units, and whe**  **n intersecting buried faults at approximately 1,742 ft**  **and 2,442 ft bml. Proposed Kodiak Site B Clearance Letter** 

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 10 FORUM ENERGY TECHNOLOGIES, INC. Closing

**We appreciate the opportunity to be of service to D eep Gulf Energy Companies, and look forward to**  **working together on future projects.**

**Sincerely,**

GEOSCIENCE EARTH & MARINE SERVICES

**Oluwayomi Oyedele Daniel Lanier Geoscientist**  **Director – Geoscience Earth & Marine Services**

**Erin Williams Janes Project Manager/Senior Geoscientist** 

**Attachments (5 Maps and 3 Illustrations)**

**Distribution: Mr. Barry G. Hexton, Deep Gulf Energy Companies (6 copies)** 

REFERENCES

**AOA Geophysics Inc., 2009, Interpretation of wireli ne logging data and integration with other relevant**  **data, Kodiak geotechnical investigation, Mississippi Canyon, Gul**  **f of Mexico: Report prepared for BP America Inc., R eport No.**  **4041-BP-GOM-KOD-01.**

**Bureau of Ocean Energy Management, 2013a, ASCII Dat a Files, published on the BOEM Gulf of Mexico Regio**  **n Homepage, <http://www.gomr.boem.gov/homepg/pubinfo/**  **freeasci/freedesc.html>, accessed December, 2013.**

**Bureau of Ocean Energy Management, 2013b, Explorati on Plan Control # S-07369, published on the BOEM Gu**  **lf of Mexico Region Homepage, <**  **http://www.data.boem.gov/PI/PDFImages/PLANS/30/3073 9.pdf>, accessed June,**  **2013.**

**Bureau of Ocean Energy Management, 2011, Notice to lessees and operators (NTL) of federal oil and gas**  **leases and pipeline right-of-way (ROW) holders on the oute**  **r continental shelf (OCS), revisions to the list of OCS lease**  **blocks requiring archaeological resource surveys an d reports: U.S. Departments of the Interior, Bureau**  **of Ocean Energy Management, Bureau of Safety and Environment**  **al Enforcement, Gulf of Mexico OCS Region (GOMR), N TL**  **2011-JOINT-G01. Effective Date December 29, 2011.**

**Carney, R.S., 2008, Summary of seafloor fauna obser ved during the Tubular Bells and Kodiak appraisal a**  **rea ROV seafloor biological survey: Report prepared for BP**  **America Inc., Report No. TBEL1-10GO-RP-000013.**

**C&C Technologies Survey Services, (C&C), 2007, Arch aeological Assessment Report, Block 727 & Vicinity,**  **Mississippi Canyon Area: Report prepared for BP America Inc., J**  **ob no. 072456-073011.**

**Coffeen, J. A., 1978, Seismic Exploration Fundament als: Tulsa, the Petroleum Publishing Co., p. 125.** 

**Fugro McClelland Marine Geosciences, Inc., (FMMG), 2009a, Deepwater geotechnical investigation, Kodiak**  **Prospect SPAR development, Blocks 726, 727, 728, 770 & 771,**  **Mississippi Canyon Area, Gulf of Mexico: Report pre pared for**  **BP America Inc., Report No. 0201-6584-1, volume I. Proposed Kodiak Site B Clearance Letter** 

**Deep Gulf Energy Companies //**  **December 26, 2013**

**Geoscience Earth & Marine Services** // 11 FORUM ENERGY TECHNOLOGIES, INC. **Fugro McClelland Marine Geosciences, Inc., (FMMG), 2009b, Shallow water flow investigation, Kodiak Pro**  **spect, Blocks 727 & 771, Mississippi Canyon Area, Gulf of**  **Mexico: Report prepared for BP America Inc., Report No. 0201-**  **6584-2, volumes I, II, & III.**

**Fugro McClelland Marine Geosciences, Inc., (FMMG), 2010, Deepwater geotechnical investigation, Kodiak**  **Prospect SPAR development, Blocks 726, 727, 728, 770 & 771,**  **Mississippi Canyon Area, Gulf of Mexico: Report pre pared for**  **BP America Inc., Report No. 0201-6584-1, volume II.**

**Geoscience Earth & Marine Services, (GEMS), 2009, T ubular Bells/Kodiak development project, geologic a**  **nd stratigraphic assessment, Blocks 680 to 684, 724 to**  **728, & 768 to 772, Mississippi Canyon Area, Gulf o f Mexico,**  **Project No. 0508-1497.**

**Geoscience Earth & Marine Services, (GEMS), 2013, S eafloor verification study using ROV data, Block 72**  **7, Mississippi Canyon Area, Gulf of Mexico, Project No**  **. 0713-2273.**

**Minerals Management Service, 2005, Notice to lessee s and operators of federal oil, gas, and sulphur le**  **ases and pipeline right-of-way holders in the outer continen**  **tal shelf, Gulf of Mexico OCS region, Archaeologica l resource**  **surveys and reports: U. S. Department of the Inter ior, Minerals Management Service, Gulf of Mexico, N**  **TL 2005-G07.**

**Minerals Management Service, 2008a, Notice to lesse es and operators of federal oil, gas, and sulphur l**  **eases and pipeline right-of-way holders in the outer continen**  **tal shelf, Gulf of Mexico OCS region, information r equirements for**  **exploration plans and development operations coordi nation documents: U. S. Department of the Interior,**  **Minerals Management Service, Gulf of Mexico, NTL 2008-G04.** 

**Minerals Management Service, 2008b, Notice to lesse es and operators of federal oil, gas, and sulphur l**  **eases and pipeline right-of-way holders in the outer continen**  **tal shelf, Gulf of Mexico OCS region, shallow hazar ds requirements:**  **U. S. Department of the Interior, Minerals Manageme nt Service, Gulf of Mexico, NTL 2008-G05.** 

**Minerals Management Service, 2010, Notice to lessee s and operators of federal oil and gas leases in th**  **e outer continental shelf, Gulf of Mexico OCS region, deepw**  **ater benthic communities: U. S. Department of the I nterior,**  **Minerals Management Service, Gulf of Mexico, NTL 20 09-G40. Effective Date January 27, 2010.** Deep Gulf Energy II, LLC Section 2 – Pg. 11 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 4
HYDROGEN SULFIDE INFORMATION

4.1 CONCENTRATION DGE II does not anticipat e encountering any H 2 S during the proposed operations.

4.2 CLASSIFICATION In accordance with Title 30 CFR 250.490(c), DG E II requests that MC Block 727 Unit (Kodiak Unit) be classified by the BSEE as H 2 S absent

.
4.3 H2S CONTINGENCY PLAN Not applicable to the operations proposed in this plan.

4.4 MODELING REPORT Not applicable to the operations proposed in this plan.Deep Gulf Energy II, LLC Section 5 – Pg. 12 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 5
MINERAL RESOURCE CONSER VATION INFORMATION

5.1 TECHNOLOGY & RESERVOIR ENGINEERING PRACTICES AND
PROCEDURES Proprietary Information

5.2 TECHNOLOGY AND RECOVERY PRACTICES AND PROCEDURES Proprietary Information

5.3 RESERVOIR DEVELOPMENT Proprietary InformationDeep Gulf Energy II, LLC Section 6 – Pg. 13 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 6 BIOLOGICAL, PHYSICAL AND SO CIOECONOMIC INFORMATION

6.1 DEEPWATER BENTHIC COMMUNITIES The seafloor disturbing activi ties proposed in this plan are in water depths greater than 300 meters (984’). Geoscience Earth & Marine Se rvices, Inc. (GEMS) was contracted to provide an assessment of the shallow conditions at the proposed surface locations. The purpose of the assessment was to address seafloor conditions that may impact exploratory drilling operations within 2,000 feet of the pr oposed well sites. DGE II will avoid all high-density deepwater benthic communities by 2,000 feet from each proposed mud and cuttings discharge location and 250 feet from the location of all other seafloor disturbances. As per NTL 2009-G40, “Deep water Benthic Communities,” a map showing the 2,000 foot radius aro und the well site is included as Attachment 6-A

.

6.2 TOPOGRAPHIC FE ATURES (BANKS) Activities proposed in this DOCD do not fall within 305 meters (1000 feet) of a topographic “no activity zone”; therefore, no map is required per NTL 2009-G39, “Biologically Sensitive U nderwater Features and Areas.”

6.3 TOPOGRAPHIC FEATURES STATEMENT (SHUNTING) All activities proposed under this DOCD will be conducted outs ide all Topographic Feature Protective Zones; ther efore, shunting of drill cuttings and drilling fluids is not required per NTL 2009-G39, “B iologically Sensitive Unde rwater Features and Areas.”

6.4 LIVE-BOTTOMS (PINNACLE TREND FEATURES) MC Block 727 Unit (Kodiak Unit) is not lo cated within 61 meters (200 feet) of any pinnacle trend feature; therefore, a separate bathymetric map is not required per NTL 2009-G39, “Biologicall y Sensitive Underwate r Features and Areas.”

6.5 LIVE BOTTOMS (LOW RELIEF) MC Block 727 Unit (Kodiak Unit) is not lo cated within 30 meters (100 feet) of any pinnacle trend feature with vertical relief equal to or greater than 8 feet; therefore, live bottom (low relief) maps are not required per NTL 2009-G39, “Biologically Sensitive
Underwater Features and Areas.”

6.6 POTENTIALLY SENSITIVE BIOLOGICAL FEATURES MC Block 727 Unit (Kodiak Unit ) is not located within 30 mete rs (100 feet) of potentially sensitive biological features ; therefore, biologically s ensitive area maps are not required.Deep Gulf Energy II, LLC Section 6 – Pg. 14 of 31 Unit DOCD July, 2013 Kodiak Development Unit 6.7 REMOTELY OPERATED VEHICLE (ROV) SURVEYS
BOEM has determined there is enough data gathered in Grid Area 16; therefore, ROV surveys either pre-spudding or post-drilli ng operations per NTL 2008-G06, “Remotely Operated Vehicle Surveys in Deepwa ter,” (Extended by NTL BOEM 2013-G02, “Extension of Prior Notices to Lessees”) is not required. However; based on prior discussion with BOEM, DGE II is planning on conducting und erwater ROV surveys in
the area.

6.8 THREATENED AND ENDANGERED SPECIES, CRITICAL HABITAT, AND
MARINE MAMMAL INFORMATION Under Section 7 of the Endangered Species Ac t (ESA) all federal agencies must ensure that any actions they authorize, fund, or carry out are not likely to jeopardize the
continued existence of a list ed species, or destroy or adv ersely modify its designated
critical habitat.

In accordance with 30 CF R 550, Subpart B, and further outlined in NTL 2008-G04, “Information Requirements fo r Exploration Plans and Development Operations Coordination Documents” (Extended by NT L BOEM 2013-G02, “Extension of Prior Notices to Lessees”) and NTL 2012-JOINT-G01,“Vessel Strike Avoidance and Injured/Dead Protected Species Reporting,” lessees/operators are required to address site-specific information on the presence of federally listed th reatened or endangered species and critical habita t designated under the ESA and marine mammals protected under the Marine Mammal Protection Act (MMPA) in the area of proposes activities under this plan.

There are five species of sea turtles that ma y be found in the Gulf of Mexico (see table below). NOAA fisheries currently lists all five of these turtles as endangered (E) or threatened (T).

Species Scientific Name Status Po tential Presence Critical Habitat Designated in

the Gulf of Mexico Lease
Area Coastal

Sea Turtles Loggerhead Carettsa caretta T X X None

Green Chelonia mydas T,E X X NoneDeep Gulf Energy II, LLC Section 6 – Pg. 15 of 31 Unit DOCD July, 2013 Kodiak Development Unit

Leatherback Dermochelys corlacea E X X None

Hawksbill Eretmochelys imbricata E X X None

Kemp’s Ridley Lepidochelys kempli E X X None

In addition, there are 28 species of marine mammals that may be found in the Gulf of Mexico. The table provided below identifie s the seven (7) species of marine mammals
that are listed as e ndangered or threatened. Currently, t here are no designated critical habitats for the listed species in the Gulf of Mexico Outer Continen tal Shelf; however, it is possible that one or more of these species could be seen in the area during operations.

Species Scientific Name Status Potential
Presence Critical
Habitat Designated
in the Gulf of
Mexico Lease
Area Coastal

Marine Mammals Sperm Whale Physeter macrocephalus E X -- None

Florida Manatee Trichechusmanatus latirostris E -- X Florida (Peninsular)
Blue Whale Balaenoptera masculus E X -- None

Fin Whale Balaenoptera physalus E X -- None

Humpback Whale Megaptera novaeangliae E X -- None

North Atlantic Right Whale Eubalaena glacialis E X -- None

Sei Whale Balaenopiera borealis E X -- None

There is one (1) species of fish that NOAA fisheries currently list as threatened (T) that may be found in the Gulf of Mexico. The Gu lf sturgeon, also known as the Gulf of Mexico sturgeon, is an anadromous (breeding in freshwater after migrating up riversDeep Gulf Energy II, LLC Section 6 – Pg. 16 of 31 Unit DOCD July, 2013 Kodiak Development Unit from marine and estuarine environments) fish overwintering in est uaries, bays, and the Gulf of Mexico (see table below).

Species Scientific Name Status Potential
Presence Critical
Habitat Designated
in the Gulf of
Mexico Lease
Area Coastal

Fish Gulf sturgeon Acipenser oxyrinchus (=oxyrhynchus) desotoi T X X None

6.9 ARCHAEOLOGICAL REPORT MC Block 727 Unit (Kodiak Unit) has been determined to have a high potential for containing archaeological properties. Review of the data obtained during the shallow hazard study does not indicate the presence of any historic period shipwrecks.

Should DGE II discover man-made debris that appears to indicate the presence of a shipwreck (e.g. a sonar image or visual conf irmation of an iron, st eel or wooden hull, piles of ballast rock) within or adjacent to our lease area during the course of operations, DGE II will immediately halt operations , take steps to ensure that the site is not disturbed in any way and contact the Regional Supervisor, Leasing and Environment, within 48 hours of the discovery. DGE II will cease all operations within 1000 feet (305 meters) of the site until the Regional Director instructs our office on what steps to take to assess the site’s potentia l historical signific ance and what steps to protect it.

6.10 AIR AND WATER QUALITY INFORMATION Air and water quality information is not requir ed to be included in this plan per NTL 2008-G04, “Information Requ irements for Exploration Plans and Development Operations Coordi nation Documents.”

6.11 SOCIOECONOMIC INFORMATION
Socioeconomic Information is not required to be included in this plan per NTL 2008- G04, “Information Requirements for Explor ation Plans and Development Operations
Coordination Documents.”Deep Gulf Energy II, LLC Section 7 – Pg. 17 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 7
WASTES AND DISCHARGES INFORMATION

7.1 PROJECTED GENERATED WASTES “Wastes You Will Generate, Treat and Downho le Dispose or Discharge to the Gulf of
Mexico” is included as Attachment 7-A.

7.2 MODELING REPORT Modeling reports are not required to be submitted with this plan.ATTACHMENT7‐ADrill cuttings wetted with water-based fluidCuttings coated with water baseddrilling mud1,000 bbl/well 250 bbl/day/wellDischarged at mudline prior to BOP and riserinstallationDrill cuttings wetted with synthetic-based fluidCuttings coated with synthetic-based drilling mud9,521 bbl/well 73 bbl/day/wellDrill cuttings from the wellbore are processed usingsolids control equipment (shakers, cuttings dryer)which substantially reduces ROC percentage, andprocessed cuttings are discharged through shunt pipeto 25' below water's surfaceWill drilling occur? If yes, you should list muds and cuttingsWaste you will generate, treat and downhole dispose or discharge to the GOMProjected Generated Waste Projected Ocean DischargesType of Waste Composition ProjectedAmount Discharge Rate Discharge MethodDischarge overboardDischarged at mudline prior to BOP and riserinstallationWater-based Drilling Fluids Water based drillingfluid 40,000/bbl/well 10,000 bbl/day/wellEXAMPLE: Cuttings wetted with synthetic basedfluidCuttings generated whileusing synthetic based drillingfluidX bbl/well X bbl/day /wellWill humans be there? If yes, expect conventional wasteDomestic wasteGray water (laundry, galley,lavatory)27,251 bbl/well 5 bbl/hr/wellDischarged overboard. Associated food waste will beprocessed using an approved grinderSanitary wasteTreated human body waste fromtoilets27,251 bbl/well 5 bbl/hr/well USCG approved MSDWill you conduct well treatment, completion or workover? Ifyes, only fill in those associated with your activityWell treatment fluids KCL/HCL/NaCL/NaBr 2,000bbl/well 10 bbl/min/well Discharged overboardIs there a deck? If yes, there will be Deck DrainageDeck Drainage Platform washings and rainwater 550 bbl/well 0.1 bbl/hr/well Oily water is treated in Oily Water SeparatorMiscellaneous discharges? If yes, only fillin those associated with your activityDesalinization unit dischargeRejected water from water makerunit313,959 bbl/well 57 bbl/hr Cuttings chuteBlowout prevent fluidStackmagic 200/0/5% glycolbased on 2% mixture withpotable water384 bbl/well12 bbl/week with functiontestDischarged from BOP near mudlineBallast waterUncontaminated seawater usedto maintain proper draft49,464 bbl/well 9 bbl/hr Discharged overboardBilge Water Bilge water 550 bbl/well0.1 bbl/hr Discharged overboardExcess cement at seafloor Cement slurry 900 bbl/well 19 bbl/hrDischarged at the mudline during cementingconductor casingDischarged overboardWash water Wash water, sink drainage, etc 27,251 bbl/well 5 bbl/hr/wellFirewaterSeawater with no addition ofchemicalsN/A N/ADischarged overboardCooling water Seawater with no addition of 9,160,000 bbl/well 1,667 bbl/hr Discharged overboardWill you be covered by an individual or general NPDES permit:General - NPDES ID GMG290356NOTE: IF YOU WILL NOT HAVE A TYPE OF WASTE, ENTER“NA”IN THE ROW.Will you produce hydrocarbons? If yes, fill in for produced waterProduced water N/A N/A N/A N/ADeep Gulf Energy II, LLC Section 8 – Pg. 18 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 8
AIR EMISSIONS INFORMATION

8.1 EMISSIONS WORKSHEETS AND SCREENING QUESTIONS

Screen Procedures for DOCD’s Yes No

Is any calculated Complex Total (C T) Emission amount (tons) associated with your proposed development activi ties more than 90% of the amounts calculated using the following formulas: CT = 3400D 2/3 for CO, and CT = 33.3D for the other air pollutants (wher e D = distance to shore in miles)? X

Do your emission calculations include any emission reduction measures or modified emission factors? X
Does or will the facility comp lex associated with your proposed development and production 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 (40 kilometers) from shore? X

Are your proposed development and pr oduction activities located within 124 miles (200 kilometers) of the Breton Wil derness Area? X

8.2 SUMMARY INFORMATION

There are no co-existing facilities; therefore, the total complex emissions and the plan emissions are the same. Included as Attachment 8-A are Air Emission Worksheets which show the emissions calculations.

This information was calculated by: Kelley Pisciola (281) 578-3388 kelley.pisciola@jccteam.com

Air Emissions were calculated using Ensco 8500 Series Specific Horsepower and fuel consumption. DGE II will use a Rig equal to or si milar to an Ensco 8500 Series Rig

. Air emissions for the production life of the wells proposed in this plan will be included in the AQR submitted for the third party host facility.DOCD AIR QUALITY SCREENING CHECKLISTOMB Control No. 1010-0151OMB Approval Expires: 12/31/14COMPANYDGE IIAREAMCBLOCK727LEASEG-24102 / G24107 (Kodiak Unit)PLATFORMN/AWELLA(MC771) & B (MC727)COMPANY CONTACTKelley PisciolaTELEPHONE NO.281-698-8519REMARKSDrill, complete & produce Locations A (MC771 #2) and B (MC727 #3);install 2 lease jumper pipelines and commence production.AQR calculated using Ensco 8500 Series Specific HorsepowerLEASE TERM PIPELINE CONSTRUCTION INFORMATION:YEAR NUMBER OF TOTAL NUMBER OF CONSTRUCTION DAYSPIPELINES20142015 1 72016 1 7FORM BOEM-0139(December 2011- Supersedes all previous versions of this form which may not be used).Page 1 of 8AIR EMISSIONS CUMPUTATION FACTORSFuel Usage Conversion FactorsNatural Gas Turbines Natural Gas Engines Diesel Recip. Engine REF. DATESCF/hp-hr 9.524 SCF/hp-hr 7.143 GAL/hp-hr 0.0483AP42 3.2-1 4/76 & 8/84Equipment/Emission Factorsunits PM SOx NOx VOC CO REF. DATENG Turbines gms/hp-hr 0.00247 1.3 0.01 0.83AP42 3.2-1& 3.1-1 10/96NG 2-cycle lean gms/hp-hr 0.00185 10.9 0.43 1.5AP42 3.2-1 10/96NG 4-cycle lean gms/hp-hr 0.00185 11.8 0.72 1.6AP42 3.2-1 10/96NG 4-cycle rich gms/hp-hr 0.00185 10 0.14 8.6AP42 3.2-1 10/96Diesel Recip. < 600 hp. gms/hp-hr 1 1.468 14 1.12 3.03AP42 3.3-1 10/96Diesel Recip. > 600 hp. gms/hp-hr 0.32 1.468 11 0.33 2.4AP42 3.4-1 10/96Diesel Boiler lbs/bbl 0.084 2.42 0.84 0.008 0.21AP42 1.3-12,14 9/98NG Heaters/Boilers/Burners lbs/mmscf 7.6 0.593 100 5.5 84P42 1.4-1, 14-2, & 147/98NG Flares lbs/mmscf 0.593 71.4 60.3 388.5AP42 11.5-1 9/91Liquid Flaring lbs/bbl 0.42 6.83 2 0.01 0.21AP42 1.3-1 & 1.3-3 9/98Tank Vapors lbs/bbl 0.03E&P Forum 1/93Fugitives lbs/hr/comp. 0.0005API Study 12/93Glycol Dehydrator Vent lbs/mmscf 6.6La. DEQ 1991Gas Venting lbs/scf 0.0034Sulphur Content Source Value UnitsFuel Gas 3.33 ppmDiesel Fuel 0.4 % weightProduced Gas( Flares) 3.33 ppmProduced Oil (Liquid Flaring) 1 % weightFORM BOEM-0139(December 2011 - Supersedes all previous versions of this form which may not be used).Page 2 of 8AIR EMISSIONS CALCULATIONS - FIRST YEARCOMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKSDGE II MC 727 G-24102 / G241 N/A B Kelley Pisciola 281-698-8519OPERATIONS 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 PM SOx NOx VOC CODRILLING PRIME MOVER>600hp diesel 21739 1049.9937 25199.85 24 122 15.32 70.29 526.72 15.80 114.92 22.43 102.91 771.11 23.13 168.24PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Vessel trips / wk BURNER diesel 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00AUXILIARY EQUIP<600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002 VESSELS>600hp diesel(crew) 2065 99.7395 2393.75 8 34 1.46 6.68 50.03 1.50 10.92 0.20 0.91 6.80 0.20 1.482 VESSELS>600hp diesel(supply) 4400 212.52 5100.48 10 34 3.10 14.23 106.61 3.20 23.26 0.53 2.42 18.12 0.54 3.95VESSELS>600hp diesel(tugs) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PIPELINE PIPELINE LAY BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00INSTALLATION SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PIPELINE BURY BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(crew) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(supply) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00FACILITY DERRICK BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00INSTALLATION MATERIAL TUG diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(crew) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(supply) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PRODUCTION RECIP.<600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00TURBINE nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.2 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.4 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.4 cycle rich nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00BURNER nat gas 0 0.00 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00MISC. BPD SCF/HR COUNTTANK- 0 0 0 0.00 0.00FLARE- 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PROCESS VENT- 0 0 0 0.00 0.00FUGITIVES- 0.0 0 0.00 0.00GLYCOL STILL VENT- 0 0 0 0.00 0.00DRILLING OIL BURN 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00WELL TEST GAS FLARE 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002014 YEAR TOTAL19.88 91.20 683.36 20.50 149.10 23.16 106.24 796.04 23.88 173.68EXEMPTIONCALCULATIONDISTANCE FROM LAND INMILES1798.20 1798.20 1798.20 1798.20 48574.4754.0FORM BOEM-0139(December 2011 - Supersedes all previous versions of this form which may not be used).Page 3 of 8AIR EMISSIONS CALCULATIONS - SECOND YEARCOMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKSDGE II MC 727 G-24102 / G241N/A B Kelley Pisciola 281-698-8519 #REF!OPERATIONS 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 PM SOx NOx VOC CODRILLING PRIME MOVER>600hp diesel 21739 1049.9937 25199.85 24.00 107.00 15.32 70.29 526.72 15.80 114.92 19.67 90.26 676.30 20.29 147.56PRIME MOVER>600hp diesel 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PRIME MOVER>600hp diesel 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PRIME MOVER>600hp diesel 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Vessels trips/wk BURNER diesel 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00AUXILIARY EQUIP<600hp diesel 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002 VESSELS>600hp diesel(crew) 2065 99.7395 2393.75 6.00 31.00 1.46 6.68 50.03 1.50 10.92 0.14 0.62 4.65 0.14 1.022 VESSELS>600hp diesel(supply) 4400 212.52 5100.48 10.00 31.00 3.10 14.23 106.61 3.20 23.26 0.48 2.21 16.52 0.50 3.61VESSELS>600hp diesel(tugs) 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PIPELINE PIPELINE LAY BARGE diesel 45000 2173.5 52164.00 24 7 31.72 145.51 1090.31 32.71 237.89 2.66 12.22 91.59 2.75 19.98INSTALLATION SUPPORT VESSEL diesel 5479 264.6357 6351.26 24 7 3.86 17.72 132.75 3.98 28.96 0.32 1.49 11.15 0.33 2.43(One Pipelines) PIPELINE BURY BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SUPPORT VESSEL diesel 5479 264.6357 6351.26 8 5 3.86 17.72 132.75 3.98 28.96 0.08 0.35 2.66 0.08 0.58VESSELS>600hp diesel(crew) 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(supply) 5000 241.5 5796.00 10.00 5.00 3.52 16.17 121.15 3.63 26.43 0.09 0.40 3.03 0.09 0.66FACILITY DERRICK BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00INSTALLATION MATERIAL TUG diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(crew) 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(supply) 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PRODUCTION RECIP.<600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00TURBINE nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.2 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.4 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.4 cycle rich nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00BURNER nat gas 0 0.00 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00MISC. BPD SCF/HR COUNTTANK- 0 0 0 0.00 0.00FLARE- 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PROCESS VENT- 0 0 0 0.00 0.00FUGITIVES- 0.0 0 0.00 0.00GLYCOL STILL VENT- 0 0 0 0.00 0.00DRILLING OIL BURN 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00WELL TEST GAS FLARE 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002015 YEAR TOTAL62.85 288.30 2160.31 64.81 471.34 23.44 107.55 805.90 24.18 175.83EXEMPTIONCALCULATIONDISTANCE FROM LAND INMILES1798.20 1798.20 1798.20 1798.20 48574.4754.0FORM BOEM-0139(December 2011 - Supersedes all previous versions of this form which may not be used).Page 4 of 8AIR EMISSIONS CALCULATIONS - THIRD YEARCOMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKSDGE II MC 727 G-24102 / G241N/A A (MC771) & B (MC727) Kelley Pisciola 281-698-8519 #REF!OPERATIONS 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 PM SOx NOx VOC CODRILLING PRIME MOVER>600hp diesel 21739 1049.9937 25199.85 24 229 15.32 70.29 526.72 15.80 114.92 42.11 193.16 1447.42 43.42 315.80PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Vessels trips / wk BURNER diesel 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00AUXILIARY EQUIP<600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002 VESSELS>600hp diesel(crew) 2065 99.7395 2393.75 8 65 1.46 6.68 50.03 1.50 10.92 0.38 1.74 13.01 0.39 2.842 VESSELS>600hp diesel(supply) 4400 212.52 5100.48 10 65 3.10 14.23 106.61 3.20 23.26 1.01 4.62 34.65 1.04 7.56VESSELS>600hp diesel(tugs) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PIPELINE PIPELINE LAY BARGE diesel 45000 2173.5 52164.00 24 7 31.72 145.51 1090.31 32.71 237.89 2.66 12.22 91.59 2.75 19.98INSTALLATION SUPPORT VESSEL diesel 5479 264.6357 6351.26 24 7 3.86 17.72 132.75 3.98 28.96 0.32 1.49 11.15 0.33 2.43(One Pipeline) PIPELINE BURY BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SUPPORT VESSEL diesel 5479 264.6357 6351.26 8 5 3.86 17.72 132.75 3.98 28.96 0.08 0.35 2.66 0.08 0.58VESSELS>600hp diesel(crew) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(supply) 5000 241.5 5796.00 10 5 3.52 16.17 121.15 3.63 26.43 0.09 0.40 3.03 0.09 0.66FACILITY DERRICK BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00INSTALLATION MATERIAL TUG diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(crew) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(supply) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PRODUCTION RECIP.<600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00TURBINE nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.2 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.4 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.4 cycle rich nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00BURNER nat gas 0 0.00 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00MISC. BPD SCF/HR COUNTTANK- 0 0 0 0.00 0.00FLARE- 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PROCESS VENT- 0 0 0 0.00 0.00FUGITIVES- 0.0 0 0.00 0.00GLYCOL STILL VENT- 0 0 0 0.00 0.00DRILLING OIL BURN 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00WELL TEST GAS FLARE 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002016 YEAR TOTAL62.85 288.30 2160.31 64.81 471.34 46.65 213.99 1603.49 48.10 349.85EXEMPTIONCALCULATIONDISTANCE FROM LAND INMILES1798.20 1798.20 1798.20 1798.20 48574.4754.0FORM BOEM-0139(December 2011 - Supersedes all previous versions of this form which may not be used).Page 5 of 8AIR EMISSIONS CALCULATIONS - FOURTH YEARCOMPANY AREA BLOCK LEASE PLATFORM WELL CONTACT PHONE REMARKSDGE II MC 727 G-24102 / G241 N/A A (MC771) & B (MC727) Kelley Pisciola 281-698-8519 #REF!OPERATIONS 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 PM SOx NOx VOC CODRILLING PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PRIME MOVER>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00BURNER diesel 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00AUXILIARY EQUIP<600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(crew) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(supply) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(tugs) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PIPELINE PIPELINE LAY BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00INSTALLATION SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PIPELINE BURY BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(crew) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(supply) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00FACILITY DERRICK BARGE diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00INSTALLATION MATERIAL TUG diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(crew) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00VESSELS>600hp diesel(supply) 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PRODUCTION RECIP.<600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.>600hp diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SUPPORT VESSEL diesel 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00TURBINE nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.2 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.4 cycle lean nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00RECIP.4 cycle rich nat gas 0 0 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00BURNER nat gas 0 0.00 0.00 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00MISC. BPD SCF/HR COUNTTANK- 0 0 0 0.00 0.00FLARE- 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00PROCESS VENT- 0 0 0 0.00 0.00FUGITIVES- 0.0 0 0.00 0.00GLYCOL STILL VENT- 0 0 0 0.00 0.00DRILLING OIL BURN 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00WELL TEST GAS FLARE 0 0 0 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.002017 - 2025 YEAR TOTAL0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00EXEMPTIONCALCULATIONDISTANCE FROM LAND INMILES0.00 0.00 0.00 0.00 0.000.0FORM BOEM-0139(December 2011 - Supersedes all previous versions of this form which may not be used).Page 6 of 8AIR EMISSIONS CALCULATIONSCOMPANY AREA BLOCK LEASE PLATFORM WELLDGE II MC 727 G-24102 / G24107 (KoN/AA(MC771) & B (MC727Emitted SubstanceYearPM SOx NOx VOC CO2014 23.16 106.24 796.04 23.88 173.682015 23.44 107.55 805.90 24.18 175.832015 46.65 213.99 1603.49 48.10 349.852017-2025 0.00 0.00 0.00 0.00 0.00Allowable1798.20 1798.20 1798.20 1798.20 48574.47FORM BOEM-0139(December 2011 - Supersedes all previous versions of this form which may not be used).Page 8 of 8ACTUAL FUEL USAGE FACTORS ASSUMED FOR AQR EMISSION CALCULATIONS

Rig 1/1/2013 Fuel On Board, Bbl 7/1/2013 Fuel On Board, Bbl Fuel Taken On, Bbl Total Fuel Used,
Bbl Daily Ave. Fuel,
Bbl 8500 6580.0 10836.0 50858.0 46602.0 257.47
8501 6870.0 9284.0 48936.0 46522.0 257.03
8503 11812.0 9295.0 39202.0 41719.0 230.49
8505 10618.0 10205.0 43477.0 43890.0 242.49
246.87 bbl/day

12.95 1 Std. deviation 8500, 8501, 8503, 8505 reported fuel-on-board at beginning (01 Jan. 2013) and ending (01 July 2013) dates, also all fuel taken onbaord that period

8502.0 36582.0 202.11
8506.0 40791.0 225.36
213.74 (bbl/day)

16.44 1 Std. deviation 8502 and 8506 reported total fuel consumption for the period 01 Jan. - 01 July 2013

Rig Total Fuel Used, Bbl Daily Ave. Fuel, Bbl

6 x 8500 Series Ri g s 256106.0 235.83 bbl/day

21.15 1 Std. Deviation
63.5 3 std. deviation

299.28 bbls/day, Mean + 3 std. deviations (99.73%)

0.0483 gal/hp-hr (diesel recip. Factor, AQE)
10843.47 HP
21686.94 HP x 2

21739.00 HP used in AQE reporting

600.00 bbl/day used in AQE reporting

257.47

257.03

230.49

242.49

202.11

225.36 Daily Fuel Consumption 8500 series January 1, 2013 to July 1, 2013 (181 days)Deep Gulf Energy II, LLC Section 9 – Pg. 19 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 9
OIL SPILL INFORMATION

9.1 OIL SPILL RESPONSE PLANNING All the proposed activities and facilities in the DOCD will be covered by the Regional Oil Spill Response Plan (OSRP) filed by Deep Gulf Energy LP (BOEM Operator No. 02815) and includes Deep Gulf Energy II, LLC (BOEM Operator No. 02985), dated May 2013, last approved December 9, 2013 (O SRP Control Number O-978).

9.2 SPILL RESPONSE SITES

Primary Response Equipment Location Preplanned Staging Location

Houma, LA Houma, LA Harvey, LA Harvey, LA Leeville, LA Leeville, LA Venice, LA

9.3 OSRO INFORMATION DGE II’s primary equipment provi der is Clean Gulf Associates (CGA), and it will provide the closest available personnel, as well as a supervisor to operate the equipment.

9.4 WORST-CASE DISCHARGE SCENARIO DETERMINATION

Category Drilling Production
Regional

OSRP WCD DOCD WCD Regional OSRP WCD DOCD WCD

Type of Activity Drilling Drilling <10 / > 10 mile Production <10 / > 10 mile Production
Facility Location (Area/Block) MC 771 MC 771 MC 771 MC 771

Facility Designation #002 #002 #002 #002

Distance to Nearest Shoreline (miles) 54 54 54 54

Volume Storage tanks & flowlines Lease term pipelines Uncontrolled blowout Total Volume (bbls) 107,728 107,728 25,224 25,224Deep Gulf Energy II, LLC Section 9 – Pg. 20 of 31 Unit DOCD July, 2013 Kodiak Development Unit

Type of Oil(s) (crude, condensate, diesel) Oil Oil Oil Oil

API Gravity 35 35 35 35

The WCD calculations and assumptions fo r the Regional OSRP WCD, MC771 Well No.002 (107,728) were previously re viewed under Plan Control No. S-7624.

Since DGE II has the capability to respond to the appropriate worst-case spill scenario included in its regional OSRP approved on December 9, 2013, and since the worst-case scenario determined for our DOCD does not replace the appropriate worst-case scenario in our regional OSRP, DGE II hereby certifies that DGE II has the capability to respond, to the maximum extent practicable, to a worst-case discharge, or a substantial threat of such a discharge, resulting fr om the activities pr oposed in our DOCD.

The oil spill response discussion is included as Attachment 9-A.

The Worst Case Discharge Volume calculatio ns and assumptions used to determine the volume (daily discharge rate) of their WCD scenario were provided in the Proprietary Copy of this plan.

### ATTACHMENT 9-A

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 107,728 barrels of crude oil with an API gravity of 35°.

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 an 11% 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 part icle size and can be classified as fine sand, shell or perched shell beaches. Sandy and muddy tidal flats are also abundant.

Response

DGE II will make every effort to respond to th e Worst Case Discharge as effectively as practicable. A description of the response equipment under contra ct to contain and recover the Worst 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 21% or approximately 22,623 barrels of crude oil would be evaporated/dispersed w ithin 24 hours, with approximately 85,105 barrels remaining.

Spill Response MC 771, Well #002 Barrels of Oil

WCD Volume 107,728

Less 21% natural evaporation/dispersion 22,623
Remaining volume 85,105

Figure 2 outlines equipment, personnel, materials and support vessels as well as temporary storage equipment available to respond to a spill of approximately 85,105 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.DGE II’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 utili zed, 8 sorties (9,600 gallons) from two of the DC-3 aircrafts and 4 sorties (8,000 gall ons) from the Basler ai rcraft would provide a daily dispersant capability of 7,540 barrels. If th e conditions are favorable for in-situ burning, the proper approvals have been obtained and the prope r planning is in place, in-situ burning of oil may be attempted. Slick containment boom woul d be immediately calle d 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), a nd six sets of Koseq skimming arms, with a total derated skimming capac ity of 188,233 barrels. Temporar y storage associated with skimming equipment equals 17,700 barrels. If additi onal storage is need ed, a 47,000 barrel storage barge, three 23,000 barrel storage barges, and three 20,000 barrel storage barges may be mobilized and centrally located to provide temporary storage allowi ng the skimmers to stay in the area of operations as much as possible. Safety is first priority. Air monitoring will be accomplished and operations deemed safe prio r 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 25,200 barrels. Temporary storage associated with skim ming equipment equals 590 barrels. If additional storage is needed, a 25,000 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 possible. Onshore response may include the de ployment of shoreline bo om on beach areas, or protection and sorbent boom on vegetated areas. Master Service Agreements with AMPOL and OMI Environmental will ensure access to 147,00 0 feet of 18” shoreline protection boom. Figure
2 outlines individual times needed for procurem ent, load out, travel time to the site and deployment. Strategies would be based upon survei llance and real time traj ectories that depict areas of potential impact given actual sea and w eather conditions. The Stat e of Louisiana Initial Oil Spill Response Plan for Plaquemines Parish and Unified Command would be consulted to ensure that environmental and special economic resources would be co rrectly identified and prioritized to ensure optimal protection. Shorel ine protection strategies depict the protection response modes applicable for o il spill clean-up operati ons. The State of Louisiana Initial Oil Spill Response Plan provides detailed shoreline protection strategies for this area, and it describes necessary action to keep the oil spill from entering Louisiana’s coastal wetlands, based 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 deploym ent and operation of equipment allowing a more effective response to site-specific circumstan ces. DGE II’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 scen ario, DGE II can be onsite with contracted oil spill recovery equipment with adequate response capacity to contain and recover surface hydrocarbons, and prevent land impact, to the maximum extent practicable, within an estimated 60 hours (based on the equipment’s Effectiv e Daily Recovery Capacity (EDRC)).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

DGE II will take action to provide a safe, aggressi ve 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 se nsitive 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 establishedDecanting 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.

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 re mote sensing systems, aerial photography and visual confirmation

 Continual monitoring of vessel assets using vessel monitoring systems

Dispersant application assets

 Put Airborne Support In c. (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 operationsCGA 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

T&T Koseq Skimming Systems

 To the area of the thickest oil

 Use as far off-shore as allowed

 VOOs with a minimum of 2,000 bbls storage capacity

 VOOs at least 200’ in length

 VOOs with deck space of 100’ x 40’ to provide space for arms, tanks, and crane

 VOOs for shallow water should be deck barges wi th a draft 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 DGE II’s contracted resources as applicable

 Industry vessels are usually best for depl oyment 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 inspectionsIn-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, th e 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 orde r of the Unified Command, vessel captain, or in an emergency, ”stop work” may be directed by any crew member.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 sh oreline 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 re mote 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 DGE II’s contracted resources as applicable

 Industry vessels are usually best for depl oyment 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 patchesShoreline 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 areasDecanting 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 seasEnvironmental 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.FIGURE 1 TRAJECTORY BY LAND SEGMENT

Trajectory of a spill and the probability of it impacting a land segment have been projected utilizing DGE II’s WCD and information in the BSEE Oil Spill Risk Analysis Model (OSRAM) for the Central and Western Gulf of Mexico available on the BSEE website using 30 day impact. The results are tabulated below.

Area/Block OCS-G Launch
Area Land Segment and/or
Resource Conditional Probability (%) within 30 days

Drill, Complete and

Produce two well
locations

MC 771, Well #002

54 miles from shore G24107 C59 Cameron, LA Vermilion, LA Terrebonne, LA Lafourche, LA Jefferson, LA Plaquemines, LA

St. Bernard, LA Walton, FL

Bay, FL 1
1
2
2
1
11
2
1
1WCD Scenario– BASED ON WELLBLOWOUT DURING DRILLING OPERATIONS (54 miles from shore)85,105 bbls of crude oil (Volume considering natural weathering)API Gravity 35°FIGURE 2 – Equipment Response Time to MC 771, Well #002Dispersants/SurveillanceDispersant/SurveillanceDispersantCapacity (gal)StorageCapacityPersons Req.FromHrs toProcureHrs toLoadoutTravelto siteTotal HrsCGABasler 67T 2000 NA 2 Houma 1 1 0.7 2.7ASIDC 3 1200 NA 2 Houma 1 1 1 3DC 3 1200 NA 2 Houma 1 1 1 3Aero Commander NA NA2 Houma 1 1 0.7 2.7Offshore ResponseOffshore Equipment NoStagingEDRCStorageCapacityVOOPersonsRequiredFromHrs toProcureHrs toLoadoutHrs toGOMTravel toSpill SiteHrs toDeployTotalHrsCGAHOSS Barge 43000 4000 3 Tugs 5 Harvey 7 0 5 7.5 1 20.5Boom Barge (CGA-300)42” Auto Boom (25000’)NA NA1 Tug50 Crew4 (Barge)2 (Per Crew)Leeville 4 0 6 14.3 1.5 25.8Recovered Oil Storage NoStagingEDRCStorageCapacityVOOPersonsRequiredFromHrs toProcureHrs toLoadoutHrs toGOMTravel toSpill SiteHrs toDeployTotalHrsEnterprise Marine Services LLC (available through contract with CGA)CTCo 2604 NA 20000 1 Tug 6 Amelia 4 12 4 21.25 1 42.25CTCo 2605 NA 20000 1 Tug 6 Amelia 4 12 4 21.25 1 42.25CTCo 2606 NA 20000 1 Tug 6 Amelia 4 12 4 21.25 1 42.25CTCo 2607 NA 23000 1 Tug 6 Amelia 4 12 4 21.25 1 42.25CTCo 2608 NA 23000 1 Tug 6 Amelia 4 12 4 21.25 1 42.25CTCo 2609 NA 23000 1 Tug 6 Amelia 4 12 4 21.25 1 42.25CTCo 5001 NA 47000 1 Tug 6 Amelia 4 12 4 21.25 1 42.25Staging Area: VeniceOffshore Equipment WithStagingEDRCStorageCapacityVOOPersonsReq.FromHrs toProcureHrs toLoadoutTravel toStagingTravel toSiteHrs toDeployTotalHrsCGAFRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Galveston 1 2 8 5 1 17FRU (1) + 100 bbl Tank (1) 4251 100 1 Utility 6 Harvey 1 2 1.75 5 1 10.8FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Ingleside 1 2 11 5 1 20FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Lake Charles 1 2 5.5 5 1 14.5FRU (2) + 100 bbl Tank (2) 8502 400 2 Utility 12 Leeville 1 2 3.5 5 1 12.5FRU (1) + 100 bbl Tank (2) 4251 200 1 Utility 6 Morgan City 1 2 3.25 5 1 12.3FRU (2) + 100 bbl Tank (4) 8502 400 2 Utility 12 Venice 1 2 0 5 1 9T&T Marine (available through contract with CGA)Koseq Skimming Arms (3) 53487 6000 3 Utility 18 Leeville 24 24 3.5 5 2 58.5Koseq Skimming Arms (1) 17829 2000 1 Utility 6 Fourchon 24 24 4 5 2 59Koseq Skimming Arms (2) 35658 4000 2 Utility 12 Venice 24 24 0 5 2 55Offshore Equipment WithStagingEDRCStorageCapacityVOOPersonsReq.FromHrs toProcureHrs toLoadoutTravel toStagingTravel toSiteHrs toDeployTotalHrsCGAHydro-Fire Boom NA NA 8 Utility40 Harvey (HFB) 1 4 1.75 5 6 17.8Nearshore ResponseNearshore Equipment NoStagingEDRCStorageCapacityVOOPersonsRequiredFromHrs toProcureHrs toLoadoutHrs toGOMTravel toSpill SiteHrs toDeployTotalHrsCGA46’ FRV 5000 65 NA 4 Venice 1 0 1 2 0 4Enterprise Marine Services LLC (available through contract with CGA)CTCo 2603 NA 25000 1 Tug 6 Amelia 4 12 4 15 1 36Staging Area: VeniceNearshore and Inland SkimmersWith StagingEDRCStorageCapacityVOOPersonsReq.FromHrs toProcureHrs toLoadoutTravel toStagingTravel toDeploymentHrs toDeployTotalHrsCGASWS Egmopol 3000 100 NA 3 Galveston 1 2 8 2 0 13SWS Egmopol 3000 100 NA 3 Morgan City 1 2 3.25 2 0 8.25SWS Marco 3588 20 NA 3 LakeCharles 1 2 5.5 2 0 10.5SWS Marco 3588 34 NA 3 Leeville 1 2 3.5 2 0 8.5SWS Marco 3588 34 NA 3 Venice 1 2 0 2 0 5Rope Mop 77 2 0 3 Harvey 1 2 8 2 0 13Foilex Skim Package (TDS 150) 891 45 NA 3 Lake Charles 1 2 5.5 2 0 8Foilex Skim Package (TDS 150) 891 45 NA 3 Galveston 1 2 8 2 0 8Foilex 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 Lake Charles 1 2 5.5 2 0 8Shoreline ProtectionStaging Area: VeniceShoreline ProtectionBoomVOOPersonsReq.Storage/WarehouseLocationHrs toProcureHrs toLoadoutTravel toStagingTravel toDeployment SiteHrs toDeployTotal HrsAMPOL (available through MSA)42,000’ 18” Boom 16 Crew 40 New Iberia, LA 2 2 4 2 12 2220,000’ 18” Boom 8 Crew 20 New Orleans, LA 2 2 2 2 6 14OMI Environmental (available through MSA)10,000’ 18” Boom 4 Crew 10 New Iberia, LA 1 1 4 2 3 1110,000’ 18” Boom 4 Crew 10 Houston, TX 1 1 7.5 2 3 14.510,000’ 18” Boom 4 Crew 10 Port Arthur, TX 1 1 6.25 2 3 13.2520,000’ 18” Boom 8 Crew 20 Belle Chasse, LA 1 1 1.75 2 6 11.7510,000’ 18” Boom 4 Crew 10 Port Allen, LA 1 1 3.5 2 3 10.510,000’ 18” Boom 4 Crew 10 Houma, LA 1 1 3.5 2 3 10.515,000’ 18” Boom 6 Crew 14 Gretna, LA (Warehouse) 2 2 2 2 4 12Beach BoomEDRCStorageCapacityVOOPersonsReq.FromHrs toProcureHrs toLoadoutTravel toStagingTravel toDeploymentHrs toDeployTotalHrsCGABeach Boom (2000’) NA NA NA 6 Galveston 1 2 8 1 2 14Beach Boom (1000’) NA NA NA 4 Ingleside 1 2 11 1 2 17Beach Boom (2000’) NA NA NA 6 Pascagoula 1 2 4 1 2 10Wildlife ResponseEDRCStorageCapacityVOOPersonsReq.FromHrs toProcureHrs toLoadoutTravel toStagingTravel toDeploymentHrs toDeployTotalHrsCGAWildlife Support Trailer NA NA NA 2 Houma 1 2 3 1 2 9Bird Scare Guns (24) NA NA NA2 Belle Chasse 1 2 1.5 1 2 7.5Bird Scare Guns (12) NA NA NA 2 Galveston 1 2 8 1 2 14Bird Scare Guns (24) NA NA NA 2 Houma 1 2 3 1 2 9Bird Scare Guns (12) NA NA NA 2 Ingleside 1 2 11 1 2 17Bird Scare Guns (24) NA NA NA2 Lake Charles 1 2 5.5 1 2 11.5Bird Scare Guns (24) NA NANA 2 Pascagoula 1 2 4 1 2 10Response AssetTotalOffshore EDRC 188,233Offshore Recovered Oil Storage 193,700Nearshore / Shallow Water EDRC 25,200Nearshore / Shallow Water Recovered Oil Storage 25,590Deep Gulf Energy II, LLC Section 10– Pg. 21 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 10
ENVIRONMENTAL MONITO RING INFORMATION

10.1 MONITORING SYSTEMS
DGE II subscribes to Wilkens Weather Serv ice which provides access to real time weather conditions and provides periodi c updates on impending weather conditions such as tropical depressions, storms, and/or hurricanes entering the Gulf of Mexico.

DGE II also relies on the National Weat her Service to support the aforementioned
subscribed service. Duri ng impending inclement weather conditions, DGE II closely coordinates the activity with our contractor s and field personnel to ensure the safety of people for evacuation to ensure prot ection of the environment and the facility/equipment.

DGE II will monitor loop currents per the requi rements as set forth in NTL 2009-G02, “Ocean Current Monitoring.”

10.2 INCIDENTAL TAKES There is no reason to believe that any of the endangered species or marine mammals
as listed in the ESA will be “taken” as a re sult of the operations proposed under this plan.

It has been documented that the use of explos ives and/or seismic devices can affect marine life. Operations proposed in this pl an will not be utilizing either of these devices.

DGE II will adhere to the requirements as se t forth in the following documents, as applicable, to avoid or minimize impacts to any of the species listed in the Endangered Species Act (ESA) as a result of the operations conducted herein:

 NTL 2012-JOINT -G01, “Vessel Strike Avoidance and Injured/Dead Protected Species Reporting”

 NTL 2012-JOINT-G02, “Implementation of Seismic Survey Mitigation Measures and Protected Species Observer Program”

10.3 FLOWER GARDEN BANKS NATIONAL MARINE SANCTUARY MC Block 727 Unit (Kodiak Unit ) is not located in the Fl ower Garden Banks National Marine Sanctuary; therefore, relevant information is not required in this DOCD.Deep Gulf Energy II, LLC Section 11– Pg. 22 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 11
LEASE STIPULATIONS INFORMATION

Development activities are subject to the fo llowing stipulation attached to Lease OCS-G 24102, Mississippi Canyon Block 727 and Leas e OCS-G 24107, Mississippi Canyon
Block 771.

11.5 MARINE PROTECTED SPECIES The Marine Protected Species lease stipulat ion is meant to reduce the potential taking of marine protected species. DGE II will operate in ac cordance with NTL 2012-JOINTG01, “Vessel Strike Avoidance and Injur ed/Dead Protected Species Reporting,” to minimize the risk of vessel strikes to prot ected species and report observations of injured or dead protected spec ies, and the prevention of in tentional and/or accidental
introduction of debris into the marine environment.Deep Gulf Energy II, LLC Section 12– Pg. 23 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 12
ENVIRONMENTAL MITIGATION MEASURES INFORMATION

12.1 MEASURES TAKEN TO AVOID, MI NIMIZE, AND MITIGATE IMPACTS MC Block 727 Unit (Kodiak Unit ) is not located within Florid a; therefore, the relevant information requested is not required in this plan.

12.2 INCIDENTAL TAKES DGE II will adhere to the requirements as set forth in the following documents, as applicable, to avoid or minimize impacts to any of the species listed in the Endangered Species Act (ESA) as a result of the operations conducted herein:

 NTL 2012-JOINT-G01, “Vessel Strike Avoidance and Injured/Dead Protected Species Reporting”

 NTL 2012-JOINT-G02, “Implementation of Seismic Survey Mitigation Measures and Protected Species Observer Program”Deep Gulf Energy II, LLC Section 13– Pg. 24 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 13
RELATED FACILITIES AND OP ERATIONS INFORMATION

13.1 RELATED OCS FACILITIES AND OPERATIONS The subject wells will be protected by subsea trees, and will tie-in to the MC 727 FLET via two proposed 8-inch lease- term jumper pipelines (submi ttals pending) approximately 85 feet in length in Mississippi Canyon Bl ock 727. A proposed 8-inch right-of-way pipeline, approximately 6.25 miles in l ength, will be installed to transport produced hydrocarbons from the FLET to the existing A (Devil’s Tower) Platform located in Mississippi Canyon Block 773 with ultimate delivery of gas into Operations System MLX and ultimate delivery of liquids into Operat ions System No. 57.0. The maximum flow rate is 30,000 BOPD and 35 MMSCFD gas. The pipeline will have a shut-in time of 45
seconds.

13.2 TRANSPORTATION SYSTEM Production will flow from the host facility in Mississippi Canyon Block 773 via the Devils Tower export pipeline system. Gas will be processed, dehydrated and transported by Williams Field Services – Gulf Coast Company, L.P. (Williams) via the Williams’ Canyon Chief gas export pipeline and processed at W illiams’ Mobile Bay gas plant. Oil will be exported through an existing Lease Automati c Transfer (LACT) to the Mountaineer oil export pipeline for ultima te delivery to shore.

No new near shore or ons hore pipelines or faciliti es will be constructed.

13.3 PRODUCED LIQUID HYDROCARBONS TRANSPORTATION VESSELS There will not be any transfers of liqui d hydrocarbons other than via pipeline.Deep Gulf Energy II, LLC Section 14– Pg. 25 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 14
SUPPORT VESSELS AND AIRCRAFT INFORMATION

14.1 GENERAL The most practical, direct route from the shore base as permitted by weather and traffic
conditions will be utilized.

Type Maximum Fuel Tank Capacity Maximum
Number in Area at Any Time Trip Frequency or
Duration

High Speed Supply Vessel 3000 gal 1 2 per week

Marine Supply Vessel (MSV) 400,000 gal 2 2 per week

Crew Boat 500 bbls 1 2 per week

Helicopters 600 gal 1 6 per week

14.2 DIESEL OIL SUPPLY VESSELS

Size of Fuel Supply Vessel Capacity of Fuel Supply Vessel Frequency of Fuel
Transfers Route Fuel Supply
Vessel Will Take

Marine Supply Vessel (MSV) 400,000 gal 1 per week Direct to Fourchon

14.3 DRILLING FLUID TRANSPORTATION Drilling fluid transportation information is not required to be submitted with this plan.

14.4 SOLID AND LIQUID WASTE TRANSPORTATION A table, “Wastes You Will Transport and/or Dispose of Onshore,” is included as
Attachment 14-A.

14.5 VICINITY MAP A vicinity map showing the location of the activities proposed herein relative to the shoreline with the distance of the proposed ac tivities from the sh oreline and the primary routes of the support vessels and aircraft t hat will be used when traveling between the onshore support facilities and the drilling unit is included as Attachment 14-B.please specify whether the amount reported is a total or per wellSolid and Liquid WastestransportationType of Waste Composition Transport MethodName/Location ofFacilityAmount Disposal MethodWill drilling occur ? If yes, fill in the muds and cuttings.Oil-based drilling fluid or mudN/A N/A N/A N/A N/ASynthetic-based drilling fluid or mudinternal olefinBelow-deck storage tanks on offshoresupport vesselsM-I Swaco, PortFourchon, LA20,000 bbls/well RecycledCuttings wetted with Synthetic-based fluidCuttings generated using syntheticbased fluidBelow-deck storage tanks on offshoresupport vesselsNewport EnvironmentalServices Inc., Ingleside,TX1,000 bbls/well RecycledCuttings wetted with oil-based fluidsN/A N/A N/A N/A N/AWill you produce hydrocarbons? Ifyes fill in for produced sand.Produced sandN/A N/A N/A N/A N/AWell Completion FluidsCaBr2 / ZnBr2Below-deck storage tanks on offshoresupport vesselsNewport EnvironmentalServices Inc., Ingleside,TX6,000 bbls/well Disposed onshoreWorkover FluidsCaBr2 / ZnBr2Below-deck storage tanks on offshoresupport vesselsNewport EnvironmentalServices Inc., Ingleside,TX6,000 bbls/well Disposed onshoreTrash and debrisNon-hazardous trash & debris(non-recyclables)Transport in DOT containers on supplyvessels to shorebaseProgressive WasteSolutions of LA, Houma,LA700 lbs/well Disposed in landfillUsed oilUsed oil and glycolTransport in DOT containers on supplyvessels to shorebaseSafety Kleen System,Baton Rouge, LA420 gal/well (10bbls/well)RecycledChemical product wastesPaints, solvents, unusedchemicals, etcTransport in DOT containers on supplyvessels to shorebaseSafety Kleen System,Baton Rouge, LA130 lbs/well RecycledNOTE: Ifyou will not have a type of waste, enter NA in the row.TABLE 2. WASTES YOU WILL TRANSPORT AND /OR DISPOSE OF ONSHOREWaste DisposalWill you have additional wastes that are not permitted for discharge? If yes, fill inthe appropriate rows.Projected generated waste! ! ! !

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S h o r eDeep Gulf Energy II, LLC Section 15– Pg. 26 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 15
ONSHORE SUPPORT FACILITIES INFORMATION

15.1 GENERAL Name Location Existing/New/Modified

Fourchon C-Port Fourc hon, Louisiana Existing

15.2 SUPPORT BASE CONSTRUCTION OR EXPANSION
There will be no new construction of an onshore sup port base, nor wi ll we expand the existing shore base as a result of t he operations proposed in this DOCD.

15.3 SUPPORT BASE CONSTRUCTION OR EXPANSION TIMETABLE A support base construction or expansion time table is not required for this plan.

15.4 WASTE DISPOSAL A table, “Wastes You Will Transport and/or Dispose of Onshore,” is included as
Attachment 14-A

.Deep Gulf Energy II, LLC Section 16– Pg. 27 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 16
COASTAL ZONE MANAGEMEN T (CZM) INFORMATION

As authorized by the Federal Coastal Zo ne Management Act (CZM A), the State of Texas developed a Coastal Management Program (CMP) to allow for the review of proposed Federal license and permit activities affecting any coastal use or resource, in
or outside of the Texas Coastal Zone.

The OCS related oil and gas exploratory and de velopment activities having potential impact on the Texas Coastal Zone are based on the location of the proposed facilities, access to those sites, best practical techniq ues for drilling location s, drilling equipment guidelines for the prevention of adverse environmental effe cts, effective environmental protection, emergency pl ans and contingency plans.

Below are topics found in other sections of the plan and have been cross referenced for ease in locating:

Topic Cross Reference Comments Construction, Operation and Maintenance of Oil and Gas Exploration and Production Facilities 1 Plan Contents
2 General

Discharges of Wastewater and Disposal of Waste from Oil and Gas Exploration and Production Activities 7 Wastes and Discharges
8 Air Emissions 9 Oil Spill 14 Support Vessels and Aircraft 15 Onshore Support Facilities Construction and Operation of Solid Waste Treatment, Storage, and Disposal Facilities 7 Wastes and Discharges 14 Support Vessels and Aircraft 15 Onshore Support Facilities

Prevention, Response, and Remediation of Oil Spills 9 Oil Spill 6 Biological, Physical,
Socioeconomic 17 Environmental Impact Analysis Discharge of Municipal and Industrial Waste Water to Coastal Waters 7 Wastes and Discharges

Development in Critical Areas 6 Biological, Physical and
SocioeconomicDeep Gulf Energy II, LLC Section 16– Pg. 28 of 31 Unit DOCD July, 2013 Kodiak Development Unit 11 Lease Stipulations 12 Environmental Mitigation 15 Onshore Support Facilities 17 Environmental Impact Analysis
Construction of Waterfront Facilities and Other Structures on Submerge lands 2 General
8 Air Emissions 15 Onshore Support Facilities 17 Environmental Impact Analysis Dredging and Dredged Material Disposal and Placement 15 Onshore Support Facilities

Construction in the Beach / Dune System 15 Onshore Support Facilities

Alteration of Coastal Historic Areas 6 Biological, Physical, and
Socioeconomic 17 Environmental Impact Analysis Transportation 15 Onshore Support Facilities
Emission of Air Pollutants 8 Air Emissions 9 Oil Spill 17 Environmental Impact Analysis Appropriations of Water There will be no fresh water appropriations as a result of our operations Levee and Control Projects The proposed surface location in the Plan is located approximately 321 miles from the nearest Texas shoreline; therefore, DGE II does not anticipate an impact to the Texas Coastal Zone Management Program policies. Marine Fishery Management 17 Environmental Impact Analysis

Policies for Major Actions For purposes of this category, “majorDeep Gulf Energy II, LLC Section 16– Pg. 29 of 31 Unit DOCD July, 2013 Kodiak Development Unit actions” means an individual action relating to an activity for which a federal environmental impact statement under the National Environmental Policy Act is required. The proposed surface location addressed in the Plan would not be classified as a major action.

Relevant enforceable policies were considered in certifying consistency for Texas. A
certificate of Coastal Zone Ma nagement Consistency for the st ate of Texas is included

as Attachment 16-A

.Deep Gulf Energy II, LLC Section 17– Pg. 30 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 17 ENVIRONMENTAL IMPACT ANALYSIS (EIA)

Included as Attachment 17-A is the Environmental Impact Analysis (EIA)

### ATTACHMENT 17-A



## Deep Gulf Energy II, LLC (DGE II)

Initial Unit Development Oper ations Coordination Document Mississippi Canyon Block 727 and 771 OCS-G 24102 / OCS-G 24107

(A) IMPACT PRODUCING FACTORS

ENVIRONMENTAL IMPACT ANALYSIS WORKSHEET

Environment

Resources Impact Producing Factors (IPFs) Categories and Examples Refer to recent GOM OCS Lease Sale EIS for a more complete list of IPFs

Emissions (air, noise, light, etc.) Effluents (muds, cutting, 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) Discarded Trash & Debris

Site-specific at Offshore Location
Designated topographic features (1) (1) (1)

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

Eastern Gulf live bottoms (3) (3) (3)

Benthic communities (4)
Water quality X X

Fisheries X X

Marine Mammals X(8) X X(8) X

Sea Turtles X(8) X X(8) X
Air quality X(9)
Shipwreck sites (known or potential) (7)

Prehistoric archaeological sites X(7)

Vicinity of Offshore Location

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

Coastal and Onshore

Beaches X(6) X

Wetlands X(6)
Shore birds and coastal nesting
birds X6)

Coastal wildlife refuges

Wilderness areasFootnotes for Environmental Impact Analysis Matrix

1) Activities that may affect a marine sanctuary or topographic feature. Specifically, if th e well or platform site or any anchors will be on the seafloor within the:

o 4-mile zone of the Flower Garden Banks, or the 3-mile zone of Stetson Bank;

o 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;

o Essential Fish Habitat (EFH) criteria of 500 ft. from any no-activity zone; or

o Proximity of any submarine bank (500 ft. buffer zone) w ith relief greater than 2 meters that is not protected by the Topographic Features Stipul ation attached to an OCS lease.
2) Activities with any bottom disturbance within an OCS l ease block protected through the Live Bottom (Pinnacle Trend) Stipulation attached to an OCS lease. 3) Activities within any Eastern Gulf OCS block where seaflo or habitats are protected by the Live Bottom (LowRelief) Stipulation attached to an OCS lease. 4) Activities on blocks designated by the BOEM as being in water depths 300 meters or greater. 5) Exploration or production activities where H2S concentr ations greater than 500 ppm might be encountered. 6) All activities that could result in an accidental spill of produced liquid hydr ocarbons or diesel fuel that you determine would impact these environmental resources. If the proposed action is lo cated a sufficient distance from a resource that no impact would occur, the EIA can note that in a sentence or two. 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 leas e block in which your planned activity will occur. If the proposed activities are located a sufficient distance from a shipwreck or a 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 trans portation of produced fluids to shor e using shuttle tankers or barges.

### (B) Analysis

Site-Specific at Mississi ppi Canyon Block 727 and 771
Proposed operations consist of the drilling, co mpletion and commencement of production on two wells (MC771 #2 and MC727 #3), both of which have surface locations in Mississippi Canyon Block 727. Operations also consist of th e installation of l ease term pipelines.
The operations will be conducted with a dynamically positioned semi-submersible.

1. Designated Topographic Features
Potential IPFs on topographic features include effluents, and accidents.

Effluents: Mississippi Canyon Block 727 and 771 are approximately 50 miles from the closest designated Topographic Features Stipulation Block (Sackett Bank); therefore, no adverse impacts are expected.

Accidents: It is unlikely that an accidental surf ace or subsurface spill would occur from the proposed activities (refer to statistics in Item 5 , Water Quality). Oil spills cause damage to benthic organisms only if the oil contacts the orga nisms. Oil from a surface spill can be driven into the water column; measurable amounts have been documented down to a 10 m depth. At this depth, the oil is found only at concentrations several orders of ma gnitude lower than the
amount shown to have an effect on corals. Becau se the crests of topogr aphic features in the Northern Gulf of Mexico are found below 10 m, no oil from a surface sp ill could reach their sessile biota. Oil from a subsurface spill is not app licable due to the distance of these blocks from a topographic area. The activities proposed in this plan will be covere d by DGE II’s Regional OSRP (refer to information submitted in Section 9 ).

There are no other IPFs (includi ng emissions, physical disturbances to the seafloor and wastes sent to shore for disposal) from the proposed act ivities, which could impact topographic features.

2. Pinnacle Trend Area Live Bottoms
Potential IPFs on pinnacle trend area live bo ttoms include effluent s and accidents.

Effluents: Mississippi Canyon Block 727 and 771 are approximately 70 miles from the closest live bottom (pinnacle trend) area; therefor e, no adverse impacts are expected.

Accidents: It is unlikely that an accidental surf ace or subsurface spill would occur from the proposed activities (refer to statistics in Item 5 , Water Quality). Oil spill s have the potential to foul benthic communities and cause lethal and sublethal effects on live bottom organisms. Oil from a surface spill can be dr iven into the water column; measurable amounts have beendocumented down to a 10 m depth. At this depth, the oil is found only at concentrations several orders of magnitude lower than the amount shown to have an effect on marine organisms. Oil from a subsurface spill is not a pplicable due to the distance of these blocks from a live bottom (pinnacle trend) area. The activi ties proposed in this plan will be covered by DGE II’s Regional OSRP (refer to information submitted in Section 9 ).

There are no other IPFs (includi ng emissions, physical disturbances to the seafloor and wastes sent to shore for disposal) from the proposed activities which could impact a live bottom (pinnacle trend) area.

3. Eastern Gulf Live Bottoms

Potential IPFs on Eastern Gulf live bottoms include effluents and accidents.

Effluents: Mississippi Canyon Block 727 and 771 are not lo cated in an area characterized by the existence of live bottoms; therefore, no adverse impacts are expected.

Accidents: It is unlikely that an accidental surf ace or subsurface spill would occur from the proposed activities (refer to statistics in Item 5 , Water Quality). Oil spills cause damage to live bottom organisms only if the oil contacts the organi sms. Oil from a surface spill can be driven into the water column; measurable amounts have been documented down to a 10 m depth. At this depth, the oil is found only at concentrations several orders of ma gnitude lower than the
amount shown to have an effect on marine inve rtebrates. Oil from a subsurface spill is not applicable due to the distance of these blocks from a live bottom area. The activities proposed in this plan will be covered by DGE II’s Regional OSRP (refer to information submitted in Section 9 ).

There are no other IPFs (includi ng emissions, physical disturbances to the seafloor and wastes sent to shore for disposal) from the proposed ac tivities which could impact an Eastern Gulf live
bottom area.

4. Benthic Communities There are no IPFs (including emissions, physical di sturbances to the seaf loor, wastes sent to shore for disposal, or a ccidents) from the proposed activities that could cause impacts to benthic
communities.

A dynamically positioned semi-submersible is being used for the proposed ac tivities; therefore, only an insignificant amount of seafloor will be di sturbed. Because physical disturbances to the seafloor will be minimized by the use of a dynamically positioned semi-submersible, DGE II’s proposed operations in Mississippi Canyon Bl ock 727 and 771 would not cause impacts to
benthic communities.5. Water Quality
IPFs that could result in water quality degrada tion from the proposed oper ations in Mississippi Canyon Block 727 and 771 include effluents and accidents.

Effluents: Levels of contaminants in drilling muds and cuttings and produced water discharges, discharge-rate restrictions a nd monitoring and toxicity testin g are regulated by the EPA NPDES permit, thereby eliminating many significant bi ological or ecological effects. Operational discharges are not expected to cause si gnificant adverse impacts to water quality.

Accidents: Oil spills have the potential to alter o ffshore water quality; how ever, it is unlikely
that an accidental surface or s ubsurface spill would occur from th e proposed activities. Between 1980 and 2000, OCS operations produced 4.7 billion barrels of oil and spilled only 0.001 percent of this oil, or 1 bbl for every 81,000 bbl produced. The spill risk related to a diesel spill from drilling operations is even less. Between 1976 and 1985, (years for which da ta were collected), there were 80 reported diesel spil ls greater than one barrel associ ated with drilling activities. Considering that there were 11,944 wells drille d, this is a 0.7 percen t probability of an occurrence. If a spill were to occur, the water quality of marine waters would be temporarily affected by the dissolved components and small oil droplets. Dispersion by currents and microbial degradation would remove the oil from the water column and dilute the constituents to background levels. Historically, changes in offshore water quality from oil spills have only been detected during the life of the spill and up to seve ral months afterwards. Most of the components
of oil are insoluble in water and therefore floa t. The activities proposed in this plan will be covered by DGE II’s Regional Oil Spill Response Plan (refer to information submitted in Section 9 ).

There are no other IPFs (includi ng emissions, physical disturbances to the seafloor, and wastes sent to shore for disposal) from the proposed activities which could cause impacts to water quality.

6. Fisheries
IPFs that could cause impacts to fisheries as a result of the pr oposed operations in Mississippi Canyon Block 727 and 771 include effluents and accidents.

Effluents: Effluents such as drilling fluids and cuttings discharges contain components and properties which are detrimental to fishery resources. Moderate petroleum and metal
contamination of sediments and the water column can occur out to several hundred meters downcurrent from the discharge point. Offshore discharges are expected to disperse and dilute to very near background levels in the water column or on the seafloor within 3,000 m of the discharge point, and are expected to have negligible effect on fisheries.

Accidents: An accidental oil spill has the potent ial to cause some detrimental effects on fisheries; however, it is unlikely that such an event would occur from the proposed activities(refer to Item 5 , Water Quality). The effects of oil on mobile adult finfish or shellfish would likely be sublethal and the extent of damage woul d be reduced to the cap acity of adult fish and shellfish to avoid the spill, to metabolize hydr ocarbons, and to excrete both metabolites and parent compounds. The activities pr oposed in this plan will be covered by DGE II’s Regional OSRP (refer to information submitted in Section 9 ).

There are no IPFs from emissions, physical disturba nces to the seafloor or wastes sent to shore for disposal from the proposed activities which could cause imp acts to fisheries.

7. Marine Mammals

GulfCet II studies revealed that cetaceans of the continental shelf and shelf-edge were almost exclusively bottlenose dolphin a nd Atlantic spotted dolphin. S quid eaters, including dwarf and pygmy killer whale, Risso’s dolphin, rough-toothed dolphin, a nd Cuvier’s beaked whale, occurred most frequently along the upper slope in areas outside of anticyclones. IPFs that could cause impacts to marine mammals as a result of the proposed operations in Mississippi Canyon Block 727 and 771 include emissions, effluents, di scarded trash and debris , and accidents.

Emissions: Noises from drilling activities, support vessels and helicopters may elicit a startle
reaction from marine mammals. This reaction may lead to disruption of marine mammals’ normal activities. Stress may make them more vul nerable to parasites, disease, environmental contaminants, and/or predation (Majors and Myri ck, 1990). There is little conclusive evidence for long-term displacements and population tren ds for marine mammals relative to noise.

Effluents: Drilling fluids and cutti ngs discharges contain components which may be detrimental to marine mammals. Most operational discharges are diluted and dispersed upon release. Any potential impact from drilling flui ds would be indirect, either as a result of impacts on prey items or possibly through ingestion in the food chain (API, 1989).

Discarded trash and debris: Both entanglement in, and inge stion of debris have caused the death or serious injury of marine mammals (Laist, 1997; MMC, 1999). The limited amount of marine debris, if any, resulting from the proposed act ivities is not expected to substantially harm marine mammals. Operators are prohibited from deliberately discharging debris as mandated by
MARPOL-Annex V and the Marine Plastic Polluti on Research and Control Act, and regulations imposed by various agencies including the United States Coast Guard (USCG) and the Environmental Protection Agency (EPA).

DGE II will operate in accordance with the regulations and also avoid accidental loss of solid waste items by maintaining waste management plans, manifesting trash sent to shore, and using special precautions such as coveri ng outside trash bins to prevent accidental loss of solid waste. Special caution will be exercised when handlin g and disposing of small items and packaging materials, particularly those made of non-biode gradable, environmentally persistent materials such as plastic or glass.Informational placards will be posted on all vessels and facilities having sleeping or food preparation capabilities. All offshore personne l, including contract ors and other support services-related personnel (e.g. helicopter pilots, vessel capt ains and boat crews) will be indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint presentation), “Think About It” ( previously “All Washed Up: The Beach Litter Problem” ). Thereafter, all personnel will view the marine trash and debr is training video annually. Offshore personnel will also receive an explanation from DGE II management or the designated lease operator management that emphasizes their commi tment to waste management in accordance
with NTL No. 2012-G01.

Accidents: Collisions between support vessels and cetaceans would be unusual events, however should one occur, death or injury to marine mammals is possible. Contract vessel operators can
avoid marine mammals and reduce potential deaths by maintaining a vigilant watch for marine mammals and maintaining a safe distance when they are sighted. Vessel crews should use a reference guide to help identify the twenty-eight species of whales and dolphins, and the single species of manatee that may be encountered in the Gulf of Mexico OCS. Vessel crews must report sightings of any injured or dead protected marine mamma l species immediately, regardless of whether the injury or death is cau sed by their vessel, to the Marine Mammal and Sea Turtle Stranding Hotline at (888) 404-3922, the NMFS Southeast Regional Office at (727) 824-5312, or the Marine Mammal Stranding Networ k at (305) 862-2850. In addition, if the injury or death was caused by a collision with a contract vessel, the BOEM must be notified within 24 hours of the strike by email to protectedspecies@boemre.gov . If the vessel is the responsible party, it is required to remain available to assist the respective salvage and stranding
network as needed.

Oil spills have the potential to cause sublethal oil-related injuries and spill-related deaths to marine mammals. However, it is unlikely that an accidental oil spill would occur from the proposed activities (refer to Item 5 , Water Quality). Oil spill response activities may increase vessel traffic in the area, which could add to changes in cetacean behavior and/or distribution, thereby causing additional stress to the animals. The effect of oil dispersants on cetaceans is not known. The acute toxicity of oil dispersant chem icals included in DGE II’s OSRP is considered to be low when compared with the constituents and fractions of crude o ils and diesel products. The activities proposed in this plan will be covered by DGE II’s OSRP (refer to information
submitted in accordance with Section 9 ).

There are no other IPFs (including physical di sturbances to the seafloor) from the proposed activities which could impact marine mammals.

8. Sea Turtles
IPFs that could cause impacts to sea turtles as a result of the proposed operations include emissions, effluents, discarded tr ash and debris, and accidents. Gu lfCet II studies sighted most loggerhead, Kemp’s ridley and le atherback sea turtles over shel f waters. Historically thesespecies have been sighted up to the shelf’s edge. They appear to be more abundant east of the Mississippi River than they are west of the river (Fritts et al., 1983b; Lohoefener et al., 1990). Deep waters may be used by all sp ecies as a transitory habitat.

Emissions: Noise from drilling activi ties, support vessels, and heli copters may elicit a startle reaction from sea turtles, but th is is a temporary disturbance.

Effluents: Drilling fluids and cuttings discharges are not k nown to be lethal to sea turtles. Most operational discharges are dilu ted and dispersed upon release. Any potential impact from drilling fluids would be indirect , either as a result of impacts on prey items or possibly through ingestion in the food chain (API, 1989).

Discarded trash and debris: Both entanglement in, and inge stion of, debris have caused the death or serious injury of sea tu rtles (Balazs, 1985). The limited am ount of marine debris, if any, resulting from the proposed activitie s is not expected to substantially harm sea turtles. Operators are prohibited from deliberately discharging de bris as mandated by MARPOL-Annex V and the
Marine Plastic Pollution Research and Control Ac t, and regulations imposed by various agencies including the United States Coast Guard (USC G) and the Environmental Protection Agency (EPA). DGE II will operate in acc ordance with the regulations and also avoid accidental loss of solid waste items by maintaining waste management plans, manifesting trash sent to shore, and using special precautions such as covering outsid e trash bins to prevent accidental loss of solid waste. Special caution will be exercised when handling and disposing of small items and packaging materials, particularly those made of non-biodegradable, environmentally persistent materials such as plastic or glass.

Informational placards will be posted on all vessels and facilities having sleeping or food preparation capabilities. All offshore personne l, including contract ors and other support services-related personnel (e.g. helicopter pilots, vessel capt ains and boat crews) will be indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint presentation), “Think About It” ( previously “All Washed Up: The Beach Litter Problem” ). Thereafter, all personnel will view the marine trash and debr is training video annually. Offshore personnel will also receive an explanation from DGE II management or the designated lease operator management that emphasizes their commitment to waste management in accordance
with NTL No. 2012-G01.

Accidents: Collisions between support vessels and s ea turtles would be unusual events, however should one occur, death or injury to sea turtles is possible. Cont ract vessel operators can avoid sea turtles and reduce potential deaths by main taining a vigilant watch for sea turtles and maintaining a safe distance when they are sighte d. Vessel crews should use a reference guide to help identify the five species of sea turtles that may be encountered in the Gulf of Mexico OCS. Vessel crews must report sightings of any inju red or dead protecte d sea turtle species immediately, regardless of whethe r the injury or death is caused by their vessel, to the Marine Mammal and Sea Turtle Stranding Hotline at (888) 404-3922, the NMFS Southeast RegionalOffice at (727) 824-5312, or th e Marine Mammal Stranding Ne twork at (305) 862-2850. In addition, if the injury or death was caused by a collision with a contract vessel, the BOEM must
be notified within 24 hours of the strike by email to protectedspecies@boemre.gov . If the vessel is the responsible party, it is required to remain available to assist the respective salvage and stranding network as needed.

All sea turtle species and their life stages are vulnerab le to the harmful e ffects of oil through direct contact or by fouling of their food. Exposure to oil can be fa tal, particularly to juveniles and hatchlings. However, it is un likely that an accidental oil sp ill would occur from the proposed activities (refer to Item 5 , Water Quality). Oil sp ill response activities ma y increase vessel traffic in the area, which could add to the possibility of collisions with sea turtles. The activities proposed in this plan will be covered by DGE II’s Regional Oil Spill Re sponse Plan (refer to
information submitted in accordance with Section 9 ).

There are no other IPFs (including physical di sturbances to the seafloor) from the proposed activities which could impact sea turtles.

9. Air Quality
Mississippi Canyon Block 727 and 771 are locate d approximately 85 from the Breton Wilderness Area and approximately 55 miles from s hore. Applicable emissions data is included
in Section 8 of the Plan.

There would be a limited degree of air quality degradation in the immediate vicinity of the proposed activities. Plan Emissions for th e proposed activities do not exceed the annual exemption levels as set forth by BOEM. Acci dents and blowouts can release hydrocarbons or chemicals, which could cause the emission of air pollutants. However, th ese releases would not impact onshore air quality because of the prev ailing atmospheric cond itions, emission height, emission rates, and the distance of Mississipp i Canyon Block 727 and 771 from the coastline. There are no other IPFs (including effluents, physical disturbances to the seafloor, wastes sent to shore for treatment or disposal) from the propos ed activities which woul d impact air quality.

10. Shipwreck Sites (known or potential)
Potential IPFs that could impact known or unknown shipwreck sites as a re sult of the proposed operations in Mississippi Canyon Block 727 and 771 include disturbances to the seafloor.

Physical disturbances to the seafloor: A dynamically positioned semi-submersible is being used for the proposed activ ities; therefore, only an insignificant amount of seafloor will be disturbed. Because physical disturbances to the seafloor will be minimized by the use of a dynamically positioned semi-submersible, DGE II ’s proposed operations in Mississippi Canyon
Block 727 and 771 would not cause impacts to shipwreck sites.Additionally, Mississippi Canyon Block 727 and 771 ar e not located in or adjacent to an OCS block designated by BOEM as having a high probab ility for occurrence of shipwrecks, therefore, no adverse impacts are expected.

According to the BOEM Grid Environmenta l Assessment (EA) and ROV Status Report ( http://www.data.boem.gov/homepg/data_ center/other/ea_grid/ea_grid.asp ), Mississippi Canyon Block 727 has adequate ROV coverage due to its inclusion in Deepwate r Grid 16. Therefore, DGE II will not perform an AUV/ROV survey of the proposed well location(s) prior to or upon commencement of operations. Shou ld an historic shipwreck be encountered, DGE II will contact the BOEM immediately and make every reasonable effort to preserve and protect that cultural

resource.

There are no other IPFs (includi ng emissions, effluents, wastes sent to shore for treatment or disposal, or accidents) from the proposed activitie s that could cause impacts to shipwreck sites.

11. Prehistoric Archaeological Sites IPFs that could cause impacts to prehistoric archaeological site s as a result of the proposed operations in Mississippi Canyon Block 727 and 771 are physical dist urbances to the seafloor and accidents (oil spills).

Physical Disturbances to the seafloor: Although the operations proposed will be conducted by utilizing a dynamically positioned semi-submersible, which would cause only an insignificant
amount of seafloor to be di sturbed, Mississippi Canyon Block 727 and 771 are located inside the Archaeological Prehistoric high probability lines. DGE II will report to BOEM the discovery of any object of prehistoric archaeological signi ficance and make every reasonable effort to preserve and protect that cultural resource.

According to the BOEM Grid Environmenta l Assessment (EA) and ROV Status Report ( http://www.data.boem.gov/homepg/data_ center/other/ea_grid/ea_grid.asp ), Mississippi Canyon Block 727 and 771 have adequate ROV coverage due to their inclusion in Deepwater Grid 16. Therefore, DGE II will not perf orm an AUV/ROV survey of the proposed well location(s) prior to or upon commencement of operations. Shoul d a seafloor archaeological resource be encountered, DGE II will contact the BOEM immedi ately and make every reasonable effort to preserve and protect that cultural resource.

Accidents: An accidental oil spill has the potentia l to cause some detrimental effects to prehistoric archaeological sites if the release were to occur subsea. However, it is unlikely that an accidental oil spill would occur from the proposed activities (refer to Item 5 , Water Quality). The activities proposed in this plan will be covered by DGE II’s Regional Oil Spill Response Plan (refer to information submitted in accordance with Section 9 ).

There are no other IPFs (including emissions, effluents or wastes sent to shore for treatment or disposal) from the proposed activ ities which could impact prehistoric archeological sites.Vicinity of Offshore Location

1. Essential Fish Habitat (EFH)
IPFs that could cause impacts to EFH as a resu lt of the proposed oper ations in Mississippi Canyon Block 727 and 771 include effluents and accidents. EFH includes all estuarine and
marine waters and substrates in the Gulf of Mexico.

Effluents: The Live Bottom Low Relief Stipulati on, the Live Bottom (Pinnacle Trend) Stipulation, and the Eastern Gulf Pinnacle Trend Stipulation would prevent most of the potential impacts on live-bottom communities and EFH from operational waste discharges. Levels of contaminants in drilling muds and cuttings a nd produced-water discha rges, discharge-rate restrictions, and monitoring a nd toxicity testing are regulated by the EPA NPDES permit, thereby eliminating many significa nt biological or ecol ogical effects. Operat ional discharges are not expected to cause significant adverse impacts to EFH.

Accidents: An accidental oil spill has the potential to cause some detrimental effects on EFH. Oil spills that contact coastal bays and estuaries, as well as OCS waters when pelagic eggs and larvae are present, have the greatest potential to a ffect fisheries. However, it is unlikely that an oil spill would occur from the proposed activities (refer to Item 5 , Water Quality). The activities proposed in this plan will be covered by DGE II’s Regional OSRP (refer to information
submitted in Section 9 ).

There are no other IPFs (includi ng emissions, physical disturbances to the seafloor and wastes sent to shore for treatment or disposal) from th e proposed activities whic h could impact essential
fish habitat.

2. Marine and Pelagic Birds
IPFs that could impact marine birds as a result of the proposed activities include air emissions, accidental oil spills, and discarded trash a nd debris from vessel s and the facilities.

Emissions: Emissions of pollutants into the atmo sphere from these activities are far below
concentrations which could harm coastal and marine birds.

Accidents: An oil spill woul d cause localized, low-level petroleum hydrocarbon contamination. However, it is unlikely that an oil spill woul d occur from the proposed activities (refer to Item 5

, Water Quality). Marine and pelagic birds feedi ng at the spill location may experience chronic, nonfatal, physiological stress. It is expected th at few, if any, coastal and marine birds would actually be affected to that extent. The activit ies proposed in this plan will be covered by DGE II’s Regional OSRP (refer to information submitted in Section 9 ).Discarded trash and debris : Marine and pelagic birds could become entangled and snared in discarded trash and debris, or in gest small plastic debris, which can cause permanent injuries and death. Operators are prohibited from deliberat ely discharging debris as mandated by MARPOLAnnex V and the Marine Plastic Pollution Resear ch and Control Act, and regulations imposed by various agencies including the United States Coast Guard (USCG) and the Environmental Protection Agency (EPA). DGE II will operate in accordance with the regulations and also avoid accidental loss of solid waste items by maintaini ng waste management plans, manifesting trash sent to shore, and using special precautions such as covering outside trash bins to prevent accidental loss of solid waste. Special caution w ill be exercised when handling and disposing of small items and packaging materials, par ticularly those made of non-biodegradable, environmentally persistent materials such as plastic or glass. Informational placards will be posted on all vessels and facilities having sleeping or food preparation capabilities. All offshore personnel, including contractors and other suppor t services-related pers onnel (e.g. helicopter pilots, vessel captains and boat cr ews) will be indoctrinated on wa ste procedures, and will view the video (or Microsoft PowerPoint presentation), “Think About It” ( previously “All Washed Up: The Beach Litter Problem” ). Thereafter, all personnel will view the marine trash and debris training video annually. Offshore personnel will also receive an explanation from DGE II management or the designated lease operator ma nagement that emphasizes their commitment to waste management in accordance with NTL No . 2012-G01. Debris, if any, from these proposed
activities will seldom interact with marine and pelagic birds; therefore, the effects will be negligible.

There are no other IPFs (including effluents, physical disturbances to the seafloor, or wastes sent to shore for treatment or disposal) from the pr oposed activities which could impact marine and pelagic birds.

3. Public Health and Safety Due to Accidents.
There are no IPFs (emissions, effluents, physical disturbances to the seafloor, wastes sent to shore for treatment or disposal or accidents, including an accidental H 2 S release) from the proposed activities which could cau se impacts to public health a nd safety. In accordance with NTL No.’s 2008-G04, 2009-G27, and 2009-G31, suffi cient information is included in Section 4 to justify our request that our proposed activities be classified by BSEE as H 2 S absent.

Coastal and Onshore

1. Beaches
IPFs from the proposed activities that could cause impacts to beaches include accidents (oil spills) and discarded trash and debris.

Accidents: Oil spills contacting beaches would have impacts on the use of recreational beaches
and associated resources. Due to the distance fr om shore (55 miles) and the response capabilities that would be implemented, no significant adverse impacts are expected. The activities proposedin this plan will be covered by DGE II’s Regional OSRP (refer to information submitted in Appendix I ).

Discarded trash and debris: Trash on the beach is recogni zed as a major threat to the enjoyment and use of beaches. There will only be a limited amount of marine debris, if any, resulting from the proposed activ ities. Operators are prohibite d from deliberately discharging debris as mandated by MARPOL-Annex V and th e Marine Plastic Pollution Research and Control Act, and regulations imposed by variou s agencies including the United States Coast Guard (USCG) and the Environmental Protecti on Agency (EPA). DGE II will operate in accordance with the regulations and also avoi d accidental loss of solid waste items by maintaining waste management plans, manifes ting trash sent to shore, and using special precautions such as covering outside trash bins to prevent accidental loss of solid waste. Special caution will be exercised when handling and dispos ing of small items and packaging materials, particularly those made of non- biodegradable, environmentally pe rsistent materials such as plastic or glass.

Informational placards will be posted on all vessels and facilities having sleeping or food preparation capabilities. All offshore personne l, including contract ors and other support services-related personnel (e.g. helicopter pilots, vessel capt ains and boat crews) will be indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint presentation), “Think About It” ( previously “All Washed Up: The Beach Litter Problem” ). Thereafter, all personnel will view the marine trash and debr is training video annually. Offshore personnel will also receive an explanation from DGE II management or the designated lease operator management that emphasizes their commi tment to waste management in accordance
with NTL No. 2012-G01.

There are no other IPFs (emissions , effluents, physical disturbances to the seaflo or, or wastes sent to shore for treatment or disposal) from th e proposed activities which could impact beaches.

2. Wetlands
IPFs from the proposed activities that could ca use impacts to wetlands include accidents (oil spills) and discarded trash and debris.

Accidents: It is unlikely that an oil spill would occu r from the proposed activities (refer to Item 5 , Water Quality). Due to the distance from shor e (55 miles) and the response capabilities that would be implemented, no impacts are expected. The activities proposed in this plan will be covered by DGE II’s Regional OSRP (refer to information submitted in Section 9 ).

Discarded trash and debris: There will only be a limited amount of marine debris, if any, resulting from the proposed activ ities. Operators are prohibite d from deliberately discharging debris as mandated by MARPOL-Annex V and th e Marine Plastic Pollution Research and Control Act, and regulations imposed by variou s agencies including the United States CoastGuard (USCG) and the Environmental Protecti on Agency (EPA). DGE II will operate in accordance with the regulations and also avoi d accidental loss of solid waste items by maintaining waste management plans, manifes ting trash sent to shore, and using special precautions such as covering outside trash bins to prevent accidental loss of solid waste. Special caution will be exercised when handling and dispos ing of small items and packaging materials, particularly those made of non- biodegradable, environmentally pe rsistent materials such as plastic or glass.

Informational placards will be posted on all vessels and facilities having sleeping or food preparation capabilities. All offshore personne l, including contract ors and other support services-related personnel (e.g. helicopter pilots, vessel capt ains and boat crews) will be indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint presentation), “Think About It” ( previously “All Washed Up: The Beach Litter Problem” ). Thereafter, all personnel will view the marine trash and debr is training video annually. Offshore personnel will also receive an explanation from DGE II management or the designated lease operator management that emphasizes their commi tment to waste management in accordance
with NTL No. 2012-G01.

There are no other IPFs (emissions , effluents, physical disturbances to the seaflo or, or wastes sent to shore for treatment or disposal) fr om the proposed activities which could impact
wetlands.

3. Shore Birds and Coastal Nesting Birds

Accidents: Oil spills could cause impacts to shore bird s and coastal nesting birds. However, it is unlikely that an oil spill would occur from the proposed activities (refer to Item 5 , Water Quality). Given the distance from shore (55 mile s) and the response capabilities that would be implemented, no impacts are expected. The activ ities proposed in this plan will be covered by DGE II’s Regional OSRP (refer to information submitted in Section 9 ).

Discarded trash and debris: Coastal and marine birds are highly susceptible to entanglement in floating, submerged, and beached marine debris : specifically plastics. Operators are prohibited from deliberately discharging debris as manda ted by MARPOL-Annex V and the Marine Plastic
Pollution Research and Control Ac t, and regulations imposed by va rious agencies including the United States Coast Guard (USCG) and the Envi ronmental Protection Agency (EPA). DGE II will operate in accordance with the regulations a nd also avoid accidental loss of solid waste items by maintaining waste management plans, mani festing trash sent to shore, and using special precautions such as covering outside trash bins to pr event accidental loss of solid waste. Special caution will be exercised when handling and dispos ing of small items and packaging materials, particularly those made of non- biodegradable, environmentally pe rsistent materials such as plastic or glass.

Informational placards will be posted on vessels and every facility that has sleeping or food preparation capabilities. All offshore personne l, including contract ors and other support services-related personnel (e.g. helicopter pilots, vessel capt ains and boat crews) will beindoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint presentation), “Think About It” ( previously “All Washed Up: The Beach Litter Problem” ). Thereafter, all personnel will view the marine trash and debr is training video annually. Offshore personnel will also receive an explanation from DGE II management or the designated lease operator management that emphasizes their commi tment to waste management in accordance
with NTL No. 2012-G01.

There are no other IPFs (emissions , effluents, physical disturbances to the seaflo or, or wastes sent to shore for treatment or disposal) from th e proposed activities that could cause impacts to shore birds and coastal nesting birds.

4. Coastal Wildlife Refuges

Accidents: An accidental oil spill from the proposed activities could cause impacts to coastal wildlife refuges. However, it is unlikely that an oil spill would occur from the proposed activities (refer to Item 5, Water Quality). Due to the di stance from shore (55 miles) and the response capabilities that would be implemented, no impacts ar e expected. The activities proposed in this plan will be covered by DGE II’s Regional OSRP (refer to information submitted in Section 9 ).

Discarded trash and debris: Operators are prohibited from de liberately discharging debris as mandated by MARPOL-Annex V, the Marine Plas tic Pollution Research and Control Act and regulations imposed by various ag encies including the United St ates Coast Guard (USCG) and the Environmental Protection Agency (EPA). DGE II will operate in accordance with the regulations and also avoid accide ntal loss of solid waste items by maintaining waste management plans, manifesting trash sent to shore, and us ing special precautions such as covering outside trash bins to prevent accidental loss of solid waste. Special caution will be exercised when handling and disposing of small items and packagi ng materials, particularly those made of nonbiodegradable, environmentally persistent materials such as plastic or glass.

Informational placards will be posted on vessels and every facility that has sleeping or food preparation capabilities. All offshore personne l, including contract ors and other support services-related personnel (e.g. helicopter pilots, vessel capt ains and boat crews) will be indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint presentation), “Think About It” ( previously “All Washed Up: The Beach Litter Problem” ). Thereafter, all personnel will view the marine trash and debr is training video annually. Offshore personnel will also receive an explanation from DGE II management or the designated lease operator management that emphasizes their commi tment to waste management in accordance
with NTL No. 2012-G01.

There are no other IPFs (emissions , effluents, physical disturbances to the seaflo or, or wastes sent to shore for treatment or disposal) from th e proposed activities that could cause impacts to coastal wildlife refuges.5. Wilderness Areas

Accidents: An accidental oil spill from the proposed activities could cause impacts to wilderness areas. However, it is unlikely that an oil spill would occur from the proposed activities (refer to Item 5 , Water Quality). Due to the distance from the nearest designated Wilderness Area (85 miles) and the response capabilities that would be implemented, no significant adverse impacts are expected. The activities proposed in this plan will be covered by DGE II’s Regional OSRP (refer to information submitted in Section 9).

Discarded trash and debris: Operators are prohibited from de liberately discharging debris as mandated by MARPOL-Annex V, the Marine Plas tic Pollution Research and Control Act and regulations imposed by various ag encies including the United St ates Coast Guard (USCG) and the Environmental Protection Agency (EPA). DGE II will operate in accordance with the regulations and also avoid accide ntal loss of solid waste items by maintaining waste management plans, manifesting trash sent to shore, and us ing special precautions such as covering outside trash bins to prevent accidental loss of solid waste. Special caution will be exercised when handling and disposing of small items and packagi ng materials, particularly those made of nonbiodegradable, environmentally persistent materials such as plastic or glass.

Informational placards will be posted on vessels and every facility that has sleeping or food preparation capabilities. All offshore personne l, including contract ors and other support services-related personnel (e.g. helicopter pilots, vessel capt ains and boat crews) will be indoctrinated on waste procedures, and will view the video (or Microsoft PowerPoint presentation), “Think About It” ( previously “All Washed Up: The Beach Litter Problem” ). Thereafter, all personnel will view the marine trash and debr is training video annually. Offshore personnel will also receive an explanation from DGE II management or the designated lease operator management that emphasizes their commi tment to waste management in accordance with NTL No. 2012-G01.

There are no other IPFs (emissions , effluents, physical disturbances to the seaflo or, or wastes sent to shore for treatment or disposal) from th e proposed activities that could cause impacts to
wilderness areas.

6. Other Environmental Resources Identified

There are no other environmental resources identified for this impact assessment.

(C) IMPACTS ON PROPOSED ACTIVITIES
The site–specific environmental conditions have been taken into account for the proposed activities. No impacts are expected on the propos ed activities from site-specific environmental
conditions.

(D) ENVIRONMENTAL HAZARDS During the hurricane season, June through November , the Gulf of Mexico is impacted by an average of ten tropical storms (39-73 mph winds), of which si x become hurricanes ( > 74 mphwinds). Due to their location in the gulf, Mississippi Canyon Block 727 and 771 may experience hurricane and tropical storm force winds, and rela ted sea currents. These factors can adversely impact the integrity of the operations covere d by this plan. A significant storm may present physical hazards to operators and vessels, damage exploration or production equipment, or result
in the release of hazardous ma terials (including hydrocarbons). Additionally, the displacement of equipment may disrupt the local benthic hab itat and pose a threat to local species.

The following preventative measures included in this plan may be implemented to mitigate these impacts:

1. Drilling & completion

a. Secure well
b. Secure rig / platform

c. Evacuate personnel Drilling activities will be conducted in accordance with NTL No.’s 2008-G09, 2009-G10, and
2010-N10.

2. Platform / Strucure Installation Operator will not conduct platform / stru cture installation opera tions during Tropical
Storm or Hurricane threat.

3. Pipeline Installation Operator will not conduct pipeline installation operations during Tropical Storm or
Hurricane threat.

(E) ALTERNATIVES
No alternatives to the proposed activities were cons idered to reduce environmental impacts.

(F) MITIGATION MEASURES
No mitigation measures other than those requ ired by regulation will be employed to avoid, diminish, or eliminate potential im pacts on environmental resources.

(G) CONSULTATION
No agencies or persons were consulted regard ing potential impacts associ ated with the proposed activities. Therefore, a list of such entities has not been provided.(H) PREPARER(S)

Matt Harlan J. Connor Consulting, Inc. 16225 Park Ten Place, Suite 700 Houston, TX 77084 (281) 578-3388 matt.harlan@jccteam.com

(I) REFERENCES

Authors:

American Petroleum Institute (API). 1989. Eff ects of offshore petroleum operations on cold
water marine mammals: a literature revi ew. Washington, DC: American Petroleum Institute. 385 pp.

Balazs, G.H. 1985. Impact of ocean debris on mari ne turtles: entanglement and ingestion. In: Shomura, R.S. and H.O. Yoshida, eds. Proceedings, Workshop on the Fate and Impact of Marine Debris, 26-29 November 1984, Honolu lu, HI. U.S. Dept. of Commerce. NOAA Tech. Memo. NOAA-TM-NMFS-SWFC-54. Pp 387-429.

Burke, C.J. and J.A. Veil. 1995. Potential benef its from regulatory cons ideration of synthetic drilling muds. Environmental Assessmen t Division, Argonne Na tional Laboratory,
ANL/EAD/TM-43.

Daly, J.M. 1997. Controlling the discharge of synthetic-based drilling fluid contaminated cuttings in waters of the United States. U. S. Environmental Protection Agency, Office of Water. Work Plan, June 24, 1997.

Hansen, D.J. 198l. The relative sens itivity of seabird populations in Al aska to oil pollution. U.S. Dept. of the Interior, Bureau of Land Mana gement, Alaska OCS Region, Anchorage. BLMYK-ES-81-006-1792.

Laist, D.W. 1997. Impacts of marine debris: en tanglement of marine life in marine debris including a comprehensive list of species with entanglement and ingestion records. In: Coe, J.M. and D.B. Rogers, eds. Marine debris: s ources, impacts, and solutions. New York, NY: Springer-Verlag. Pp. 99-139.

Majors, A.P. and A.C. Myrick, Jr. 1990. Effects of noise on animals: implications for dolphins exposed to seal bombs in the eastern tropi cal Pacific purse-sein e fishery–an annotated bibliography. NOAA Admini strative Report LJ-90-06.

Marine Mammal Commission. 1999. A nnual report to Congress – 1998.Piatt, J.F., C.J. Lensink, W. Butler, M. Ke ndziorek, and D.R. Nysewander. 1990. Immediate impact of the Exxon Valdez oil spill on marine birds. The Auk. 107 (2): 387-397

Vauk , G., E. Hartwig, B. Reineking, and E. Vauk-Hentzelt. 1989. Losses of seabirds by oil pollution at the German North Sea coast. Topics in Marine Biology. Ros, J.D, ed. Scient. Mar. 53 (2-3): 749-754.

Vermeer, K. and R. Vermeer, 1975 Oil threat to birds on the Canadian west coast. The Canadian Field-Naturalist. 89:278-298.

Although not cited, the following were utilized in prepar ing this EIA:

 Hazard Surveys

 BOEM EIS’s:

o GOM Deepwater Operations and Activities. Environmental Assessment. BOEM 2000-
001

o GOM Central and Western Planning Areas Sales 166 and 168 Final Environmental Impact Statement. BOEM 96-0058.Deep Gulf Energy II, LLC Section 18– Pg. 31 of 31 Unit DOCD July, 2013 Kodiak Development Unit SECTION 18
ADMINISTRATIVE INFORMATION

18.1 EXEMPTED INFORMATION DESCRIPTION The proposed bottom-hole locations of the planned wells have been removed from the Public Information copy of the DOCD as we ll as any discussions of the target objectives, geologic or geophysical data, and any interpreted geology.

18.2 BIBLIOGRAPHY 1. Development Operations C oordination Document (N-8279) 2. Supplemental Exploration Plan (S-6804) 3. Supplemental Exploration Plan (S-7135) 4. Regional Oil Spill Response Plan (O-578) 5. Supplemental Development Operati ons Coordination Document (S-7624)