U.S. Department of the Interior

Bureau of Ocean Energy Management

Gulf of Mexico OCS Region

OCS EIS/EA

BOEM 2016-018

Gulf of Mexico OCS 

Oil and Gas Lease Sales: 2017-2022

Gulf of Mexico Lease Sales 249, 250, 251, 252, 253, 

254, 256, 257, 259, and 261

Draft Environmental Impact Statement

Volume II: Chapters 5-8, Appendices, and Keyword Index

U.S. Department of the Interior

Bureau of Ocean Energy Management

Gulf of Mexico OCS Region

OCS EIS/EA

BOEM 2016-018

Gulf of Mexico OCS 

Oil and Gas Lease Sales: 2017-2022

Gulf of Mexico Lease Sales 249, 250, 251, 252, 253, 

254, 256, 257, 259, and 261

Draft Environmental Impact Statement

Volume II: Chapters 5-8, Appendices, and Keyword Index

Author

Bureau of Ocean Energy Management

Gulf of Mexico OCS Region

Published by

New Orleans

April 2016

Table of Contents v 

TABLE OF CONTENTS

Volume I

Page

EXECUTIVE SUMMARY ..................................................................................................................... vii

LIST OF FIGURES.............................................................................................................................. xlv

LIST OF TABLES................................................................................................................................xlix

ABBREVIATIONS AND ACRONYMS ................................................................................................... li

CONVERSION CHART .......................................................................................................................lvii

1 PURPOSE OF AND NEED FOR THE PROPOSED ACTIONS..................................................... 1-3

1.1 Purpose of the Proposed Actions .................................................................................. 1-4

1.2 Need for the Proposed Actions...................................................................................... 1-5

1.3 OCS Oil and Gas Program Planning and Decision Process ......................................... 1-6

1.3.1 Prelease Process......................................................................................................... 1-7

1.3.1.1 Five-Year Program of Proposed Offshore Lease Sales ............................... 1-7

1.3.1.2 Individual Lease Sale Consultation and Decision Process........................... 1-8

1.3.2 Gulf of Mexico Postlease Activities............................................................................ 1-10

1.4 The Decision to be Made ............................................................................................. 1-11

1.5 Regulatory Framework................................................................................................. 1-11

1.6 Other OCS Oil- and Gas-Related Activities................................................................. 1-13

1.7 Other Pertinent Environmental Reviews or Documentation........................................ 1-16

1.8 Format and Organization of the Multisale EIS............................................................. 1-19

2 ALTERNATIVES INCLUDING THE PROPOSED ACTIONS......................................................... 2-3

2.1 Multisale NEPA Analysis................................................................................................ 2-3

2.2 Lease Sale Options, Alternatives, Mitigating Measures, and Issues............................. 2-5

2.2.1 Lease Sale Options in the Five-Year Program............................................................ 2-5

2.2.2 Description of the Alternatives for This Multisale EIS.................................................. 2-6

2.2.2.1 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative)..................................................................................................... 2-6

2.2.2.2 Alternative B—Regionwide OCS Lease Sale Excluding Available 

Unleased Blocks in the WPA Portion of the Proposed Lease Sale Area ..... 2-8

2.2.2.3 Alternative C—Regionwide OCS Lease Sale Excluding Available 

Unleased Blocks in the CPA/EPA Portions of the Proposed Lease Sale 

Area ............................................................................................................. 2-10

2.2.2.4 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, 

Live Bottom (Pinnacle Trend), and/or Blocks South of Baldwin County, 

Alabama, Stipulations.................................................................................. 2-11

2.2.2.5 Alternative E—No Action............................................................................. 2-14

2.2.3 Alternatives and Deferrals Considered but Not Analyzed in Detail........................... 2-15

2.2.4 Mitigating Measures................................................................................................... 2-22

2.2.4.1 Proposed Prelease Mitigating Measures (Stipulations).............................. 2-23

2.2.4.2 Prelease Mitigating Measures (Stipulations) by Alternative........................ 2-27

2.2.4.3 Postlease Mitigating Measures ................................................................... 2-27

2.2.5 Issues ......................................................................................................................... 2-29

2.2.5.1 Issues to be Analyzed ................................................................................. 2-29

2.2.5.2 Issues Considered but Not Analyzed.......................................................... 2-32
vi Gulf of Mexico Multisale EIS

2.3 Comparison of Impacts by Alternative ......................................................................... 2-33

2.4 Summary of Impacts .................................................................................................... 2-35

2.4.1 Air Quality................................................................................................................... 2-35

2.4.2 Water Quality.............................................................................................................. 2-35

2.4.3 Coastal Habitats......................................................................................................... 2-36

2.4.3.1 Estuarine Systems (Wetlands and Seagrasses/Submerged 

Vegetation) .................................................................................................. 2-36

2.4.3.2 Coastal Barrier Beaches and Associated Dunes........................................ 2-36

2.4.4 Deepwater Benthic Communities............................................................................... 2-37

2.4.5 Sargassum and Associated Communities................................................................. 2-37

2.4.6 Live Bottoms............................................................................................................... 2-38

2.4.6.1 Topographic Features ................................................................................. 2-38

2.4.6.2 Pinnacles and Low-Relief Features ............................................................ 2-39

2.4.7 Fish and Invertebrate Resources............................................................................... 2-39

2.4.8 Birds ........................................................................................................................... 2-40

2.4.9 Protected Species...................................................................................................... 2-40

2.4.9.1 Marine Mammals ......................................................................................... 2-40

2.4.9.2 Sea Turtles .................................................................................................. 2-41

2.4.9.3 Beach Mice.................................................................................................. 2-42

2.4.9.4 Protected Birds ............................................................................................ 2-42

2.4.9.5 Protected Corals.......................................................................................... 2-43

2.4.10Commercial Fisheries ................................................................................................ 2-43

2.4.11Recreational Fishing .................................................................................................. 2-44

2.4.12Recreational Resources............................................................................................. 2-44

2.4.13Archaeological Resources ......................................................................................... 2-44

2.4.14Human Resources and Land Use (Including Environmental Justice)....................... 2-45

2.4.14.1 Land Use and Coastal Infrastructure .......................................................... 2-45

2.4.14.2 Economic Factors........................................................................................ 2-46

2.4.14.3 Social Factors (Including Environmental Justice) ....................................... 2-46

3 IMPACT-PRODUCING FACTORS AND SCENARIO.................................................................... 3-3

3.1 Impact-Producing Factors and Scenario—Routine Operations .................................... 3-7

3.1.1 Resource Estimates and Timetables........................................................................... 3-7

3.1.2 Exploration and Delineation....................................................................................... 3-10

3.1.2.1 Geological and Geophysical Surveys ......................................................... 3-10

3.1.2.2 Exploration and Delineation Plans and Drilling........................................... 3-16

3.1.3 Offshore Development and Production...................................................................... 3-21

3.1.3.1 Development and Production Drilling.......................................................... 3-21

3.1.3.2 Offshore Production Systems...................................................................... 3-26

3.1.3.3 Infrastructure Emplacement/Structure Installation and Commissioning 

Activities....................................................................................................... 3-30

3.1.3.3.1 Bottom-Area Disturbance.......................................................... 3-33

3.1.3.3.2 Sediment Displacement ............................................................ 3-35

3.1.3.4 Infrastructure Presence ............................................................................... 3-35

3.1.3.4.1 Anchoring................................................................................... 3-35

3.1.3.4.2 Space-Use Requirements ......................................................... 3-36

3.1.3.4.3 Structure Lighting ...................................................................... 3-37

3.1.3.5 Workovers and Abandonments................................................................... 3-37

3.1.4 Transport.................................................................................................................... 3-38

3.1.4.1 Pipelines ...................................................................................................... 3-38

3.1.4.2 Barges ......................................................................................................... 3-43

3.1.4.3 Oil Tankers .................................................................................................. 3-44

3.1.4.4 Service Vessels ........................................................................................... 3-46
Table of Contents vii

3.1.4.5 Helicopters................................................................................................... 3-47

3.1.4.6 Navigation Channels ................................................................................... 3-48

3.1.5 Discharges and Wastes ............................................................................................. 3-53

3.1.5.1 Operational Wastes and Discharges Generated by OCS Oil- and GasRelated Facilities ......................................................................................... 3-53

3.1.5.1.1 Produced Waters....................................................................... 3-61

3.1.5.1.2 Well-Treatment, Workover, and Completion Fluids .................. 3-63

3.1.5.1.3 Production Solids and Equipment............................................. 3-65

3.1.5.1.4 Bilge, Ballast, and Fire Water.................................................... 3-65

3.1.5.1.5 Cooling Water............................................................................ 3-66

3.1.5.1.6 Deck Drainage........................................................................... 3-66

3.1.5.1.7 Treated Domestic and Sanitary Wastes.................................... 3-67

3.1.5.1.8 Minor/Miscellaneous Discharges .............................................. 3-67

3.1.5.2 Operational Wastes and Discharges Generated by Service Vessels......... 3-67

3.1.5.3 Onshore Disposal of Waste and Discharge Generated Offshore or 

Onshore....................................................................................................... 3-69

3.1.5.3.1 Onshore Disposal of Wastes Generated from OCS 

Oil- and Gas-Related Facilities.................................................. 3-69

3.1.5.3.2 Onshore Disposal and Storage Facilities Supporting 

OCS-Generated Operational Wastes........................................ 3-70

3.1.5.3.3 Discharges from Onshore Support Facilities ............................ 3-70

3.1.5.3.4 Beach Trash and Debris............................................................ 3-70

3.1.6 Decommissioning and Removal Operations ............................................................. 3-71

3.1.6.1 Structure Age and Idle Iron ......................................................................... 3-73

3.1.6.2 Rigs-to-Reefs Policy.................................................................................... 3-74

3.1.7 Coastal Infrastructure................................................................................................. 3-75

3.1.7.1 Construction Facilities ................................................................................. 3-77

3.1.7.1.1 Platform Fabrication Yards........................................................ 3-77

3.1.7.1.2 Shipbuilding and Shipyards....................................................... 3-78

3.1.7.1.3 Pipe-Coating Facilities and Yards ............................................. 3-79

3.1.7.2 Support Facilities and Transportation ......................................................... 3-79

3.1.7.2.1 Service Bases and Ports ........................................................... 3-79

3.1.7.2.2 Helicopter Hubs......................................................................... 3-82

3.1.7.2.3 Tanker Port Areas ..................................................................... 3-82

3.1.7.2.4 Barge Terminals ........................................................................ 3-83

3.1.7.2.5 Pipeline Shore Facilities ............................................................ 3-83

3.1.7.2.6 Navigation Channels ................................................................. 3-84

3.1.7.2.7 Waste Disposal Facilities .......................................................... 3-84

3.1.7.2.8 Natural Gas Storage Facilities................................................... 3-84

3.1.7.3 Processing Facilities.................................................................................... 3-85

3.1.7.3.1 Gas Processing Plants .............................................................. 3-85

3.1.7.3.2 Refineries................................................................................... 3-86

3.1.7.3.3 Onshore Liquefied Natural Gas Facilities.................................. 3-86

3.1.7.3.4 Petrochemical Plants................................................................. 3-87

3.1.8 Air Emissions.............................................................................................................. 3-87

3.1.8.1 Drilling.......................................................................................................... 3-88

3.1.8.2 Production.................................................................................................... 3-89

3.1.8.3 Vessel Support Operations and Activities during Offshore Oil and 

Gas Activities............................................................................................... 3-89

3.1.8.4 Flaring and Venting ..................................................................................... 3-89

3.1.8.5 Fugitive Emissions....................................................................................... 3-90

3.1.8.6 Greenhouse Gases ..................................................................................... 3-90

3.1.8.7 Decommissioning ........................................................................................ 3-91
viii Gulf of Mexico Multisale EIS

3.1.9 Noise .......................................................................................................................... 3-91

3.1.10New and Unusual Technology................................................................................... 3-94

3.2 Impact-Producing Factors and Scenario—Accidental Events..................................... 3-95

3.2.1 Oil Spills ..................................................................................................................... 3-95

3.2.1.1 Past OCS Spills ........................................................................................... 3-96

3.2.1.1.1 Trends in Reported Spill Volumes and Numbers...................... 3-96

3.2.1.1.2 Coastal Spills............................................................................. 3-98

3.2.1.2 Offshore Spills ...........................................................................................3-102

3.2.1.3 Characteristics of OCS Oil ........................................................................3-106

3.2.1.4 Transport and Fate of Offshore Spills .......................................................3-107

3.2.1.5 Analysis of Offshore Spills ≥1,000 bbl.......................................................3-110

3.2.1.5.1 Overview of Spill Risk Analysis ...............................................3-110

3.2.1.5.2 Trajectory Modeling for Offshore Spills ≥1,000 bbl.................3-111

3.2.1.5.3 Estimated Number of Offshore Spills ≥1,000 bbl and 

Probability of Occurrence........................................................3-113

3.2.1.5.4 Most Likely Source of Offshore Spills ≥1,000 bbl ...................3-115

3.2.1.5.5 Most Likely Size of an Offshore Spill ≥1,000 bbl.....................3-115

3.2.1.5.6 Length of Coastline Affected by Offshore Spills 

≥1,000 bbl................................................................................3-115

3.2.1.5.7 Risk Analysis by Resource......................................................3-116

3.2.1.5.8 Likelihood of an Offshore Spill ≥1,000 bbl Occurring and 

Contacting Coastal and Offshore Areas..................................3-116

3.2.1.6 Analysis of Offshore Spills <1,000 bbl.......................................................3-117

3.2.1.6.1 Estimated Number of Offshore Spills <1,000 bbl and 

Total Volume of Oil Spilled......................................................3-117

3.2.1.6.2 Most Likely Source and Type of Offshore Spills 

<1,000 bbl................................................................................3-117

3.2.1.6.3 Most Likely Size of Offshore Spills <1,000 bbl........................3-117

3.2.1.6.4 Likelihood of an Offshore Spill <1,000 bbl Occurring and 

Contacting Coastal and Offshore Areas..................................3-117

3.2.1.7 Analysis of Coastal Spills ..........................................................................3-118

3.2.1.7.1 Estimated Number and Most Likely Sizes of Coastal 

Spills ........................................................................................3-118

3.2.1.7.2 Likelihood of Coastal Spill Contact..........................................3-118

3.2.2 Losses of Well Control .............................................................................................3-118

3.2.3 Accidental Air Emissions..........................................................................................3-121

3.2.3.1 Hydrogen Sulfide and Sulfurous Petroleum..............................................3-122

3.2.4 Pipeline Failures.......................................................................................................3-123

3.2.5 Vessel and Helicopter Collisions..............................................................................3-124

3.2.6 Chemical and Drilling-Fluid Spills ............................................................................3-126

3.2.7 Spill Response .........................................................................................................3-128

3.2.7.1 BSEE Spill-Response Requirements and Initiatives.................................3-128

3.2.7.1.1 Spill-Response Requirements.................................................3-128

3.2.7.1.2 Spill-Response Initiatives ........................................................3-130

3.2.7.2 Offshore Response, Containment, and Cleanup Technology ..................3-130

3.2.7.2.1 Mechanical Cleanup................................................................3-133

3.2.7.2.2 Spill Treating Agents ...............................................................3-136

3.2.7.2.3 In-situ Burning .........................................................................3-139

3.2.7.2.4 Natural Dispersion...................................................................3-139

3.2.7.3 Onshore Response and Cleanup..............................................................3-140

3.3 Cumulative Activities and OCS Oil and Gas Program Scenario ...............................3-146

3.3.1 Cumulative OCS Oil and Gas Program Scenario....................................................3-146

3.3.1.1 Cumulative OCS Oil and Gas Program Projected Production..................3-148
Table of Contents ix

3.3.1.2 Cumulative Geological and Geophysical Surveys ....................................3-149

3.3.1.3 Cumulative Exploration and Delineation Plans and Drilling......................3-150

3.3.1.4 Cumulative Development and Production Drilling.....................................3-150

3.3.1.5 Infrastructure Emplacement/Structure Installation and 

Decommissioning Activities.......................................................................3-151

3.3.1.6 Infrastructure Presence .............................................................................3-152

3.3.1.7 Transport ...................................................................................................3-152

3.3.1.8 Discharges and Wastes.............................................................................3-154

3.3.1.9 Decommissioning and Removal Operations.............................................3-154

3.3.1.10 Coastal Infrastructure ................................................................................3-154

3.3.1.11 Air Emissions.............................................................................................3-154

3.3.2 Non-OCS Oil- and Gas-Related Impact-Producing Factors....................................3-155

3.3.2.1 State Oil and Gas Activity..........................................................................3-155

3.3.2.1.1 State Pipeline Infrastructure....................................................3-158

3.3.2.1.2 Artificial Reefs..........................................................................3-159

3.3.2.2 Marine Vessel Activity ...............................................................................3-160

3.3.2.2.1 Marine Transportation .............................................................3-160

3.3.2.2.2 Other Marine Vessel Traffic.....................................................3-162

3.3.2.2.3 Anchoring.................................................................................3-162

3.3.2.2.4 Tankering.................................................................................3-162

3.3.2.3 Non-OCS Oil- and Gas-Related Wastes and Discharges ........................3-162

3.3.2.3.1 Potentially Polluting Shipwrecks..............................................3-163

3.3.2.3.2 Discharges Associated with Military Activities ........................3-163

3.3.2.3.3 Historical Chemical Weapon Disposal Areas..........................3-165

3.3.2.3.4 Historical Industrial Waste Dumping Areas.............................3-165

3.3.2.3.5 Dredged Material Disposal......................................................3-166

3.3.2.3.6 Land-Based Discharges ..........................................................3-168

3.3.2.3.7 Trash and Debris.....................................................................3-169

3.3.2.4 Non-OCS Oil- and Gas-Related Spills ......................................................3-169

3.3.2.5 Non-OCS Oil- and Gas- Related Air Emissions........................................3-172

3.3.2.6 Other Non-OCS Oil- and Gas-Related Activities ......................................3-172

3.3.2.6.1 Military Warning and Water Test Areas ..................................3-172

3.3.2.6.2 Offshore Deepwater Ports and Nearshore Liquefied 

Natural Gas Terminals.............................................................3-174

3.3.2.6.3 Development of Gas Hydrates ................................................3-176

3.3.2.6.4 Renewable Energy and Alternative Use .................................3-177

3.3.2.6.5 Aquaculture..............................................................................3-179

3.3.2.6.6 OCS Sand Borrowing ..............................................................3-180

3.3.2.7 Noise from Non-OCS Oil- and Gas-Related Sources...............................3-183

3.3.2.8 Coastal Environments ...............................................................................3-184

3.3.2.8.1 Sea-Level Rise and Subsidence .............................................3-184

3.3.2.8.2 Erosion.....................................................................................3-187

3.3.2.8.3 Coastal Restoration Programs ................................................3-188

3.3.2.8.4 Saltwater Intrusion...................................................................3-195

3.3.2.8.5 Maintenance Dredging and Federal Channels .......................3-195

3.3.2.9 Natural Events and Processes..................................................................3-197

3.3.2.9.1 Physical Oceanography ..........................................................3-197

3.3.2.9.2 Natural Seeps..........................................................................3-198

3.3.2.9.3 Hurricanes ...............................................................................3-199

3.3.2.9.4 Climate Change.......................................................................3-200

3.3.2.10 Mississippi River Hydromodification..........................................................3-200

3.3.2.11 Mississippi River Eutrophication................................................................3-201
x Gulf of Mexico Multisale EIS

3.3.2.12 Hypoxia......................................................................................................3-202

3.3.2.13 Sedimentation............................................................................................3-204

4 DESCRIPTION OF THE AFFECTED ENVIRONMENT AND IMPACT ANALYSIS....................... 4-3

4.1 Air Quality..................................................................................................................... 4-11

4.1.1 Description of the Affected Environment ................................................................... 4-14

4.1.2 Environmental Consequences................................................................................... 4-22

4.1.2.1 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative)................................................................................................... 4-36

4.1.2.2 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed 

Lease Sale Area.......................................................................................... 4-36

4.1.2.3 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area.......................................................................................... 4-37

4.1.2.4 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, 

Live Bottom (Pinnacle Trend), and/or Blocks South of Baldwin County, 

Alabama, Stipulations.................................................................................. 4-37

4.1.2.5 Alternative E—No Action............................................................................. 4-37

4.2 Water Quality................................................................................................................ 4-37

4.2.1 Description of the Affected Environment ................................................................... 4-41

4.2.2 Environmental Consequences................................................................................... 4-43

4.2.2.1 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative)................................................................................................... 4-49

4.2.2.2 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed 

Lease Sale Area.......................................................................................... 4-49

4.2.2.3 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area.......................................................................................... 4-50

4.2.2.4 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, 

Live Bottom (Pinnacle Trend), and/or Blocks South of Baldwin County, 

Alabama, Stipulations.................................................................................. 4-50

4.2.2.5 Alternative E—No Action............................................................................. 4-50

4.3 Coastal Habitats........................................................................................................... 4-50

4.3.1 Estuarine Systems (Wetlands and Seagrass/Submerged Vegetation)..................... 4-50

4.3.1.1 Description of the Affected Environment..................................................... 4-52

4.3.1.2 Environmental Consequences .................................................................... 4-56

4.3.1.2.1 Alternative A—Regionwide OCS Lease Sale (The 

Preferred Alternative) ................................................................ 4-73

4.3.1.2.2 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area ............................................. 4-74

4.3.1.2.3 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area............................... 4-74

4.3.1.2.4 Alternative D—Alternative D—Alternative A, B, or C, with 

the Option to Exclude Available Unleased Blocks Subject 

to the Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama 

Stipulations ................................................................................ 4-74

4.3.1.2.5 Alternative E—No Action........................................................... 4-75
Table of Contents xi

4.3.2 Coastal Barrier Beaches and Associated Dunes....................................................... 4-75

4.3.2.1 Description of the Affected Environment..................................................... 4-76

4.3.2.2 Environmental Consequences .................................................................... 4-81

4.3.2.2.1 Alternative A—Regionwide OCS Lease Sale (The 

Preferred Alternative) ................................................................ 4-91

4.3.2.2.2 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area ............................................. 4-92

4.3.2.2.3 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area............................... 4-92

4.3.2.2.4 Alternative D—Alternative D—Alternative A, B, or C, with 

the Option to Exclude Available Unleased Blocks Subject 

to the Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ................................................................................ 4-93

4.3.2.2.5 Alternative E—No Action........................................................... 4-93

4.4 Deepwater Benthic Communities................................................................................. 4-93

4.4.1 Description of the Affected Environment ................................................................... 4-98

4.4.1.1 Chemosynthetic Communities...................................................................4-101

4.4.1.2 Deepwater Coral Communities .................................................................4-105

4.4.2 Environmental Consequences.................................................................................4-108

4.4.2.1 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative).................................................................................................4-119

4.4.2.2 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed 

Lease Sale Area........................................................................................4-119

4.4.2.3 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area........................................................................................4-120

4.4.2.4 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, 

Live Bottom (Pinnacle Trend), and/or Blocks South of Baldwin County, 

Alabama, Stipulations................................................................................4-121

4.4.2.5 Alternative E—No Action...........................................................................4-122

4.5 Sargassum and Associated Communities.................................................................4-122

4.5.1 Description of the Affected Environment .................................................................4-126

4.5.2 Environmental Consequences.................................................................................4-129

4.5.2.1 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative).................................................................................................4-136

4.5.2.2 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed 

Lease Sale Area........................................................................................4-136

4.5.2.3 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area........................................................................................4-137

4.5.2.4 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, 

Live Bottom (Pinnacle Trend), and/or Blocks South of Baldwin County, 

Alabama, Stipulations................................................................................4-137

4.5.2.5 Alternative E—No Action...........................................................................4-137
xii Gulf of Mexico Multisale EIS

4.6 Live Bottom Habitats ..................................................................................................4-137

4.6.1 Topographic Features..............................................................................................4-139

4.6.1.1 Description of the Affected Environment...................................................4-144

4.6.1.2 Environmental Consequences ..................................................................4-148

4.6.1.2.1 Alternative A—Regionwide OCS Lease Sale (The 

Preferred Alternative) ..............................................................4-156

4.6.1.2.2 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area ...........................................4-157

4.6.1.2.3 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area.............................4-157

4.6.1.2.4 Alternative D—Alternative A, B, or C, with the Option to 

Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ..............................................................................4-157

4.6.1.2.5 Alternative E—No Action.........................................................4-158

4.6.2 Pinnacles and Low-Relief Features .........................................................................4-158

4.6.2.1 Description of the Affected Environment...................................................4-163

4.6.2.2 Environmental Consequences ..................................................................4-169

4.6.2.2.1 Alternative A—Regionwide OCS Lease Sale (The 

Preferred Alternative) ..............................................................4-180

4.6.2.2.2 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area ...........................................4-181

4.6.2.2.3 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area.............................4-181

4.6.2.2.4 Alternative D—Alternative A, B, or C, with the Option to 

Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ..............................................................................4-182

4.6.2.2.5 Alternative E—No Action.........................................................4-183

4.7 Fishes and Invertebrate Resources...........................................................................4-184

4.7.1 Description of the Affected Environment .................................................................4-186

4.7.2 Environmental Consequences.................................................................................4-191

4.7.2.1 Alternatives A, B, C, and D........................................................................4-202

4.7.2.2 Alternative E—No Action...........................................................................4-203

4.8 Birds ...........................................................................................................................4-203

4.8.1 Description of the Affected Environment .................................................................4-205

4.8.2 Environmental Consequences.................................................................................4-210

4.8.2.1 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative).................................................................................................4-219

4.8.2.2 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed 

Lease Sale Area........................................................................................4-221

4.8.2.3 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area........................................................................................4-221

4.8.2.4 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, Live 
Table of Contents xiii

Bottom (Pinnacle Trend), and/or Blocks South of Baldwin County, 

Alabama, Stipulations................................................................................4-222

4.8.2.5 Alternative E—No Action...........................................................................4-223

4.9.1 Marine Mammals......................................................................................................4-228

4.9.1.1 Description of the Affected Environment...................................................4-228

4.9.1.2 Environmental Consequences ..................................................................4-240

4.9.1.2.1 Alternatives A, B, C, and D......................................................4-263

4.9.1.2.2 Alternative E—No Action.........................................................4-265

4.9.2 Sea Turtles...............................................................................................................4-265

4.9.2.1 Description of the Affected Environment...................................................4-265

4.9.2.2 Environmental Consequences ..................................................................4-275

4.9.2.2.1 Alternative A, B, C, and D .......................................................4-292

4.9.2.2.2 Alternative E—No Action.........................................................4-294

4.9.3 Beach Mice (Alabama, Choctawhatchee, Perdido Key, and St. Andrew)...............4-294

4.9.3.1 Description of the Affected Environment...................................................4-295

4.9.3.2 Environmental Consequences ..................................................................4-295

4.9.3.2.1 Alternative A—Regionwide OCS Proposed Lease Sale 

(The Preferred Alternative)......................................................4-298

4.9.3.2.2 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area ...........................................4-299

4.9.3.2.3 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area.............................4-299

4.9.3.2.4 Alternative D—Alternative A, B, or C, with the Option to 

Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ..............................................................................4-299

4.9.3.2.5 Alternative E—No Action.........................................................4-300

4.9.4 Protected Birds.........................................................................................................4-300

4.9.4.1 Description of the Affected Environment...................................................4-300

4.9.4.2 Environmental Consequences ..................................................................4-305

4.9.4.2.1 Alternative A—Regionwide OCS Proposed Lease Sale 

(The Preferred Alternative)......................................................4-308

4.9.4.2.2 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area ...........................................4-308

4.9.4.2.3 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area.............................4-308

4.9.4.2.4 Alternative D—Alternative A, B, or C, with the Option to 

Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ..............................................................................4-308

4.9.4.2.5 Alternative E—No Action.........................................................4-309

4.9.5 Protected Corals ......................................................................................................4-309

4.9.5.1 Description of the Affected Environment...................................................4-309

4.9.5.2 Environmental Consequences ..................................................................4-310

4.9.5.2.1 Alternatives A, B, and C ..........................................................4-311
xiv Gulf of Mexico Multisale EIS

4.9.5.2.2 Alternative D—Alternative A, B, or C, with the Option to 

Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ..............................................................................4-312

4.9.5.2.3 Alternative E—No Action.........................................................4-312

4.10 Commercial Fisheries ................................................................................................4-313

4.10.1Description of the Affected Environment .................................................................4-314

4.10.2Environmental Consequences.................................................................................4-316

4.10.2.1 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative).................................................................................................4-320

4.10.2.2 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed 

Lease Sale Area........................................................................................4-321

4.10.2.3 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area........................................................................................4-321

4.10.2.4 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, 

Live Bottom (Pinnacle Trend), and/or Blocks South of Baldwin County, 

Alabama, Stipulations................................................................................4-322

4.10.2.5 Alternative E—No Action...........................................................................4-322

4.11 Recreational Fishing ..................................................................................................4-323

4.11.1Description of the Affected Environment .................................................................4-324

4.11.2Environmental Consequences.................................................................................4-331

4.11.2.1 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative).................................................................................................4-335

4.11.2.2 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed Lease 

Sale Area...................................................................................................4-335

4.11.2.3 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area........................................................................................4-336

4.11.2.4 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, Live 

Bottom (Pinnacle Trend), and/or Blocks South of Baldwin County, 

Alabama, Stipulations................................................................................4-337

4.11.2.5 Alternative E—No Action...........................................................................4-337

4.12 Recreational Resources.............................................................................................4-338

4.12.1Description of the Affected Environment .................................................................4-339

4.12.2Environmental Consequences.................................................................................4-343

4.12.2.1 Alternative A—Regionwide OCS Lease Sale (The Preferred 

Alternative).................................................................................................4-353

4.12.2.2 Alternative B—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the Proposed Lease 

Sale Area...................................................................................................4-354

4.12.2.3 Alternative C—Regionwide OCS Proposed Lease Sale Excluding 

Available Unleased Blocks in the CPA/EPA Portions of the Proposed 

Lease Sale Area........................................................................................4-354

4.12.2.4 Alternative D—Alternative A, B, or C, with the Option to Exclude 

Available Unleased Blocks Subject to the Topographic Features, Live 

Bottom (Pinnacle Trend), and/or Blocks South of Baldwin County, 

Alabama, Stipulations................................................................................4-355
Table of Contents xv

4.12.2.5 Alternative E—No Action...........................................................................4-355

4.13 Archaeological Resources .........................................................................................4-356

4.13.1Description of the Affected Environment .................................................................4-357

4.13.1.1 Prehistoric..................................................................................................4-357

4.13.1.2 Historic.......................................................................................................4-359

4.13.2Environmental Consequences.................................................................................4-362

4.13.2.1 Alternatives A, B, C, and D........................................................................4-370

4.13.2.2 Alternative E—No Action...........................................................................4-371

4.14 Human Resources and Land Use..............................................................................4-371

4.14.1Land Use and Coastal Infrastructure.......................................................................4-371

4.14.1.1 Description of the Affected Environment...................................................4-373

4.14.1.2 Environmental Consequences ..................................................................4-379

4.14.1.2.1 Alternative A—Regionwide OCS Lease Sale (The 

Preferred Alternative) ..............................................................4-390

4.14.1.2.2 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area ...........................................4-392

4.14.1.2.3 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area.............................4-392

4.14.1.2.4 Alternative D—Alternative A, B, or C, with the Option to 

Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, 

Alabama, Stipulations..............................................................4-392

4.14.1.2.5 Alternative E—No Action.........................................................4-392

4.14.2Economic Factors ....................................................................................................4-393

4.14.2.1 Description of the Affected Environment...................................................4-393

4.14.2.2 Environmental Consequences ..................................................................4-398

4.14.2.2.1 Alternative A—Regionwide OCS Lease Sale (The 

Preferred Alternative) ..............................................................4-407

4.14.2.2.2 Alternative B—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the WPA Portion 

of the Proposed Lease Sale Area ...........................................4-411

4.14.2.2.3 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area.............................4-414

4.14.2.2.4 Alternative D—Alternative A, B, or C, with the Option to 

Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ..............................................................................4-418

4.14.2.2.5 Alternative E—No Action.........................................................4-418

4.14.3Social Factors (Including Environmental Justice)....................................................4-418

4.14.3.1 Description of the Affected Environment...................................................4-420

4.14.3.2 Environmental Consequences ..................................................................4-424

4.14.3.2.1 Alternative A—Regionwide OCS Lease Sale (The 

Preferred Alternative) ..............................................................4-433

4.14.3.2.2 Alternative B—Regionwide OCS Lease Sale Excluding 

Available Unleased Blocks in the WPA Portion of the 

Proposed Lease Sale Area .....................................................4-434
xvi Gulf of Mexico Multisale EIS

4.14.3.2.3 Alternative C—Regionwide OCS Proposed Lease Sale 

Excluding Available Unleased Blocks in the CPA/EPA 

Portions of the Proposed Lease Sale Area.............................4-434

4.14.3.2.4 Alternative D—Alternative A, B, or C, with the Option to 

Exclude Available Unleased Blocks Subject to the 

Topographic Features, Live Bottom (Pinnacle Trend), 

and/or Blocks South of Baldwin County, Alabama, 

Stipulations ..............................................................................4-435

4.14.3.2.5 Alternative E—No Action.........................................................4-435

4.14.3.3 Environmental Justice Determination........................................................4-435

4.15 Unavoidable Adverse Impacts of a Proposed Action ................................................4-436

4.16 Irreversible and Irretrievable Commitment of Resources ..........................................4-440

4.16.1Coastal Habitats.......................................................................................................4-440

4.16.2Biological Resources................................................................................................4-440

4.16.2.1 Threatened and Endangered Species ......................................................4-441

4.16.2.2 Fish and Invertebrate Resources, Deepwater Benthic Communities, 

Commercial Fisheries, and Recreational Fishing .....................................4-441

4.16.3Archaeological Resources .......................................................................................4-441

4.16.4Oil and Gas Development........................................................................................4-441

4.16.5Loss of Human and Animal Life...............................................................................4-441

4.17 Relationship Between the Short-term Use of Man’s Environment and the Maintenance

and Enhancement of Long-term Productivity.............................................................4-442

4.17.1Short-Term Use........................................................................................................4-442

4.17.2Relationship to Long-Term Productivity...................................................................4-443
Table of Contents xvii

Volume II 

Page

LIST OF FIGURES..............................................................................................................................xvii

LIST OF TABLES................................................................................................................................ xxi

5 CONSULTATION AND COORDINATION...................................................................................... 5-3

5.1 Development of the Proposed Actions .......................................................................... 5-3

5.2 Notice of Intent to Prepare an EIS and Call for Information .......................................... 5-4

5.3 Area ID Memorandum.................................................................................................... 5-4

5.4 Development of the Draft Multisale EIS......................................................................... 5-4

5.4.1 Summary of Scoping Comments ................................................................................. 5-6

5.4.2 Summary of Comments Received in Response to the Call for Information................ 5-9

5.4.3 Additional Public Input Opportunities......................................................................... 5-10

5.4.4 Cooperating Agencies................................................................................................ 5-10

5.5 Distribution of the Draft Multisale EIS for Review and Comment................................ 5-11

5.6 Coastal Zone Management Act ................................................................................... 5-15

5.7 Endangered Species Act.............................................................................................. 5-16

5.8 Magnuson-Stevens Fishery Conservation and Management Act ............................... 5-16

5.9 National Historic Preservation Act ............................................................................... 5-17

5.10 Government-to-Government ........................................................................................ 5-18

6 REFERENCES CITED ................................................................................................................... 6-3

7 PREPARERS.................................................................................................................................. 7-3

8 GLOSSARY .................................................................................................................................... 8-3

APPENDICES

Appendix A Postlease Permitting and Approval Processes .............................................. A-3

Appendix B Commonly Applied Mitigating Measures........................................................ B-3

Appendix C Cooperating Agency Memorandum of Agreement......................................... C-3

Appendix D Proposed Prelease Mitigating Measures (Stipulations)................................. D-3

Appendix E Oil Spill Risk Analysis Figures........................................................................ E-3

Appendix F Species not Considered Further..................................................................... F-3

Appendix G State Coastal Management Programs ........................................................... G-3

KEYWORD INDEX................................................................................................................Keywords-3

List of Figures xix

LIST OF FIGURES

Page

Figure 1-1. Proposed Regionwide Lease Sale Area Combining the Western, Central, and 

Eastern Planning Areas. ................................................................................................ 1-4

Figure 1-2. OCS Oil and Gas Program Development Process........................................................ 1-6

Figure 1-3. Planning for the Five-Year Program. ............................................................................. 1-8

Figure 1-4. Planning for Regional OCS Oil and Gas Lease Sales................................................... 1-8

Figure 1-5. Supplemental Approach Showing the Tiering Relationships for Proposed Gulf 

of Mexico Lease Sales................................................................................................. 1-10

Figure 1-6. BOEM’s Consultation Partners for Specific Federal Regulations................................ 1-12

Figure 1-7. BOEM’s Integrated Approach for Incorporating Applied Science into 

Decisionmaking............................................................................................................ 1-14

Figure 2-1. Proposed Regionwide Lease Sale Area, Encompassing the Available Unleased 

Blocks within All Three Planning Areas. ........................................................................ 2-7

Figure 2-2. Proposed Lease Sale Area for Alternative B, Excluding the Available Unleased 

Blocks in the WPA.......................................................................................................... 2-9

Figure 2-3. Proposed Lease Sale Area for Alternative C, Excluding the Available Unleased 

Blocks in the CPA and EPA. ........................................................................................ 2-10

Figure 2-4. Identified Topographic Features, Pinnacle Trend, and Blocks South of Baldwin 

County, Alabama, Stipulation Blocks in the Gulf of Mexico......................................... 2-12

Figure 2-5. Example of Excluded Blocks under Alternative D. ...................................................... 2-13

Figure 2-6. Federal OCS Blocks Subject to the Gulf Islands National Seashore Information to 

Lessees and Operators................................................................................................ 2-18

Figure 2-7. Military Warning Areas and Eglin Water Test Areas in the Gulf of Mexico. ................ 2-24

Figure 3-1. Offshore Subareas in the Gulf of Mexico....................................................................... 3-8

Figure 3-2. Typical Exploration and Production Timeline for Offshore Oil and Gas Drilling.......... 3-10

Figure 3-3. General Well Schematic............................................................................................... 3-18

Figure 3-4. Number of Exploration and Delineation Wells Drilled over the Course of a Proposed 

Action under Alternative A for 50 Years....................................................................... 3-20

Figure 3-5. Number of Production Wells Drilled over the Course of a Proposed Action under 

Alternative A for 50 Years. ........................................................................................... 3-25

Figure 3-6. Offshore Production Systems. ..................................................................................... 3-26

Figure 3-7. Number of Production Structures and Service Vessels Operating over the Course 

of a Proposed Action under Alternative A for 50 Years............................................... 3-33

Figure 3-8. Gulfwide OCS Oil- and Gas-Related Service Bases and Major Waterways............... 3-52

Figure 3-9. Water Quality Jurisdictional Boundaries for USEPA Regions 4 and 6........................ 3-54

Figure 3-10. Onshore Infrastructure. ................................................................................................ 3-76

Figure 3-11. OCS-Related Ports and Waterways in the Gulf of Mexico.......................................... 3-81

Figure 3-12. The Oil Spill Risk Analysis Model Process. ...............................................................3-111

Figure 3-13. OCS Oil and Gas Production Between 2003 and 2013.............................................3-149

Figure 3-14. Number of Production Structures Installed and Decommissioned in Past Programs 

and the Range of Future Projections that May Occur as a Result of All Past, 

Present, and Future Actions. .....................................................................................3-151

Figure 3-15. 2015 Gulf of Mexico Hypoxic Zone............................................................................3-203

Figure 4-1. Air Quality Areas of Influence (Texas, Louisiana, Mississippi, Alabama, and 

Florida) in the Gulf of Mexico OCS Region with the Class I Areas, Air Quality 

Jurisdiction Line, and OCS Lease Blocks.................................................................... 4-14

Figure 4-2. Ozone Nonattainment Status in the Gulf of Mexico Region in Louisiana and Texas.. 4-18

Figure 4-3. 2011 Platform NOx Emissions...................................................................................... 4-20

Figure 4-4. 2011 Non-Platform NOx Emissions.............................................................................. 4-20

Figure 4-5. 2011 Platform VOC Emissions .................................................................................... 4-21
xx Gulf of Mexico Multisale EIS

Figure 4-6. 2011 Non-Platform VOC Emissions............................................................................. 4-21

Figure 4-7. Year 2011 Gulfwide Emission Inventory Results for Total Platform and 

Non-Platform Criteria Pollutant Emissions (TPY). ....................................................... 4-22

Figure 4-8. Year 2011 Gulfwide Emission Inventory Results for Total Platform and 

Non-Platform Greenhouse Gas Emissions (TPY). ...................................................... 4-22

Figure 4-9. 2011 Criteria Pollutant Emissions (TPY) from Platform Sources. ............................... 4-26

Figure 4-10. 2011 Greenhouse Gases (TPY) from Platform Sources. ............................................ 4-26

Figure 4-11. Seagrass Locations of the Northern Gulf of Mexico.................................................... 4-55

Figure 4-12. Deepwater Coral Records from NOAA’s National Deep-Sea Coral and Sponge 

Database...................................................................................................................... 4-99

Figure 4-13. Estimated Distribution of Known Deepwater Benthic Communities in the Gulf of 

Mexico as of 2015. .....................................................................................................4-102

Figure 4-14. BOEM’s Water Bottom Seismic Anomaly Database Showing Grouped Anomaly 

Categories Thought Likely to Support Deepwater Benthic Communities and 

Those That Generally Do Not ....................................................................................4-104

Figure 4-15. Example of a Predictive Habitat Suitability Model for Selected Deepwater, 

Framework-Forming Scleractinian Corals .................................................................4-107

Figure 4-16. Sargassum Loop System...........................................................................................4-125

Figure 4-17. Lease Blocks Subject to the Topographic Features and Live Bottom (Pinnacle 

Trend) Stipulations. ....................................................................................................4-138

Figure 4-18. Ecological Representation of Common Features on Topographic Features in the 

Gulf of Mexico. ...........................................................................................................4-140

Figure 4-19. General Location of the Pinnacle Trend (A), Multibeam Bathymetry and Named 

Reef Areas (B), and an Exaggerated Vertical Relief Profile of Rough Tongue 

Reef (C)......................................................................................................................4-166

Figure 4-20. Migration Routes for Trans-Gulf Migratory Birds in the Presence of an Eastern 

Continental High.........................................................................................................4-208

Figure 4-21. Migration Routes for Trans-Gulf Migratory Birds in the Presence of a Bermuda 

High. ...........................................................................................................................4-209

Figure 4-22. Platform Density and Spring Migration Routes for Trans-Gulf Migratory Birds.........4-209

Figure 4-24. Gulf Islands National Seashore. ................................................................................4-343

Figure 4-25. Historical Structure Locations near Horn and Petit Bois Islands...............................4-346

Figure 4-26. Photograph of Remaining OCS Structures taken from Petit Bois Island Looking 

South ..........................................................................................................................4-346

Figure 4-27. Economic Land Use Patterns. ...................................................................................4-377

Figure 4-28. Historical Land Loss in Louisiana, 1932-2010...........................................................4-388

Figure 4-29. Moderate Scenario: Projected Land Loss in Louisiana............................................4-389

Figure 4-30. Less Optimistic Scenario: Projected Land Loss in Louisiana...................................4-389

Figure 4-31. Population of BOEM’s Economic Impact Areas in the Gulf of Mexico. .....................4-421

Figure 4-32. Percentage of Poverty in Texas and Louisiana.........................................................4-422

Figure 4-33. Percentage of Poverty in Mississippi, Alabama, and Florida. ...................................4-423

Figure 4-34. Percentage of Minority Populations in Texas and Louisiana.....................................4-424

Figure 4-35. Percentage of Minority Populations in Mississippi, Alabama, and Florida................4-424

Figure 5-1. Timeline for the Development of This Multisale EIS...................................................... 5-3

Figure E-1. The Oil Spill Risk Analysis Domain............................................................................... E-4

Figure E-2. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

the Shoreline (counties and parishes) as a Result of Alternative A. ............................ E-4

Figure E-3. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

the Shoreline (counties and parishes) as a Result of Alternative A. ............................ E-5

Figure E-4. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

the Shoreline (counties and parishes) as a Result of Alternative B. ............................ E-5

Figure E-5. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

the Shoreline (counties and parishes) as a Result of Alternative B. ............................ E-6
List of Figures xxi

Figure E-6. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

the Shoreline (counties and parishes) as a Result of Alternative C............................. E-6

Figure E-7. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

the Shoreline (counties and parishes) as a Result of Alternative C............................. E-7

Figure E-8. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the Low Case in Resource Estimates 

for Alternative A............................................................................................................. E-7

Figure E-9. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the High Case in Resource Estimates 

for Alternative A............................................................................................................. E-8

Figure E-10. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the Low Case in Resource Estimates 

for Alternative A............................................................................................................. E-8

Figure E-11. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the High Case in Resource Estimates 

for Alternative A............................................................................................................. E-9

Figure E-12. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the Low Case in Resource Estimates 

for Alternative B. ............................................................................................................ E-9

Figure E-13. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the High Case in Resource Estimates 

for Alternative B........................................................................................................... E-10

Figure E-14. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the Low Case in Resource Estimates 

for Alternative B........................................................................................................... E-10

Figure E-15. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the High Case in Resource Estimates 

for Alternative B........................................................................................................... E-11

Figure E-16. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the Low Case in Resource Estimates 

for Alternative C........................................................................................................... E-11

Figure E-17. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the High Case in Resource Estimates 

for Alternative C........................................................................................................... E-12

Figure E-18. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the Low Case in Resource Estimates 

for Alternative C........................................................................................................... E-12

Figure E-19. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days 

Nearshore (“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to 

outer jurisdiction) Polygons as a Result of the High Case in Resource Estimates 

for Alternative C........................................................................................................... E-13
xxii Gulf of Mexico Multisale EIS

Figure E-20. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days 

and 30 Days State Offshore Waters as a Result of Alternative A, B, or C................. E-13
List of Tables xxiii

LIST OF TABLES

Page

Table 2-1. Applicable Stipulations by Alternative.......................................................................... 2-27

Table 2-2. Alternative Comparison Matrix..................................................................................... 2-33

Table 3-1. Projected Oil and Gas in the Gulf of Mexico OCS......................................................... 3-8 

Table 3-2. Offshore Scenario Activities Related to a Single Lease Sale for Alternative A, B, 

or C from 2017 through 2066......................................................................................... 3-9 

Table 3-3. Oil Transportation Scenario under Alternative A, B, or C............................................ 3-38

Table 3-4. Existing Coastal Infrastructure Related to OCS Oil- and Gas-Related Activities 

in the Gulf of Mexico. ................................................................................................... 3-39

Table 3-5. OCS Pipeline Landfalls Installed from 1996 to 2014................................................... 3-43

Table 3-6. Waterway Length, Depth, Traffic, and Number of Trips for 2012................................ 3-49

Table 3-7. Pollution-Related Incidents of Noncompliance Issued from 1986 to the Present. ...... 3-56

Table 3-8. National Pollutant Discharge Elimination System Inspections from 1999 through 

2014.............................................................................................................................. 3-57

Table 3-9. Annual Volume of Produced Water Discharged by Depth (millions of bbl)................. 3-63

Table 3-10. OCS Oil- and Gas-Related Service Bases. ................................................................. 3-80

Table 3-11. Annual Summary of Number and Total Volume of Oil Spilled into the Gulf of 

Mexico, 2001-2015....................................................................................................... 3-96

Table 3-12. Spill Rates for Petroleum Spills ≥1,000 Barrels from OCS Platforms and Pipelines, 

1964 through 2010....................................................................................................... 3-98

Table 3-13. Historic Spill Source, Location, and Characteristics of a Maximum Spill for Coastal 

Waters and Offshore Waters. ....................................................................................3-100

Table 3-14. Petroleum Spills ≥1,000 Barrels from United States OCS Platforms, 1964-2015.....3-103

Table 3-15. Petroleum Spills ≥1,000 Barrels from United States OCS Pipelines, 1964-2015. ....3-105

Table 3-16. Properties and Persistence by Oil Component Group...............................................3-107

Table 3-17. Probability (percent chance) of a Particular Number of Offshore Spills ≥1,000 

Barrels Occurring as a Result of Either Facility or Pipeline Operations Related to 

Alternative A, B, or C..................................................................................................3-112

Table 3-18. Mean Number and Sizes of Spills Estimated to Occur in OCS Offshore Waters 

from an Accident Related to Rig/Platform and Pipeline Activities Supporting Each 

Alternative Over a 50-Year Time Period....................................................................3-113

Table 3-19. Oil-Spill Occurrence Probability Estimates for Offshore Spills ≥1,000 Barrels 

Resulting from Each Alternative (2017-2066) and the Cumulative OCS Oil and 

Gas Program (2017-2086). ........................................................................................3-114

Table 3-20. Oil-Spill Occurrence Probability Estimates for Offshore Spills ≥10,000 Barrels 

Resulting from Each Alternative (2017-2066) and the Cumulative OCS Oil and 

Gas Program (2017-2086). ........................................................................................3-114

Table 3-21. Number and Volume of Chemical and Synthetic-Based Fluid Spills for 10-49 

Barrels and >50 Barrels in the Gulf of Mexico from 2007 through 2014...................3-127

Table 3-22. Primary Cleanup Options Used during the Deepwater Horizon Response...............3-131

Table 3-23. Future Activity Projections Associated with the Cumulative OCS Oil and Gas 

Program (2017-2086), Including All Future Activities that are Projected to Occur 

from Past, Proposed, and Future Lease Sales..........................................................3-147

Table 3-24. Future Oil Transportation Projections Associated with the Cumulative OCS Oil and 

Gas Program (2017-2086), Including All Future Transportation that is Projected to 

Occur from Past, Proposed, and Future Lease Sales...............................................3-153

Table 3-25. Number of Vessel Calls at U.S. Gulf Ports Between 2002 and 2011........................3-161

Table 3-26. Quantities of Dredged Materials Disposed of in Ocean Dredged-Material Disposal 

Sites Between 2004 and 2013...................................................................................3-167
xxiv Gulf of Mexico Multisale EIS

Table 3-27. Average Annual Inputs of Petroleum Hydrocarbons to Coastal Waters of the 

Gulf of Mexico, 1990-1999.........................................................................................3-170

Table 3-28. Average Annual Inputs of Petroleum Hydrocarbons to Offshore Waters of the 

Gulf of Mexico, 1990-1999.........................................................................................3-171

Table 3-29. Projected OCS Sand Resource Needs for Planned Restoration Projects. ...............3-180

Table 3-30. Hurricane Landfalls in the Northern Gulf of Mexico from 1995 through 2015...........3-199

Table 3-31. Oil Spilled from Pipelines on the Federal OCS, 2002-2009. .....................................3-200

Table 4-1. Air Quality Impact-Producing Factors. ......................................................................... 4-12

Table 4-2. National Ambient Air Quality Standards. ..................................................................... 4-16

Table 4-3. Water Quality Impact-Producing Factors..................................................................... 4-39

Table 4-4. Estuarine Systems Impact-Producing Factors............................................................. 4-51

Table 4-5. Coastal Barrier Beaches and Associated Dunes Impact-Producing Factors.............. 4-75

Table 4-6. Deepwater Benthic Communities Impact-Producing Factors...................................... 4-96

Table 4-7. Sargassum and Associated Communities Impact-Producing Factors. .....................4-123

Table 4-8. Topographic Features Impact-Producing Factors. ....................................................4-141

Table 4-9. Pinnacles and Low-Relief Features Impact-Producing Factors. ...............................4-159

Table 4-10. Fish and Invertebrate Resources Impact-Producing Factors....................................4-186

Table 4-11. Birds Impact-Producing Factors.................................................................................4-204

Table 4-12. Species within the Gulf of Mexico That Are Protected Under the Endangered 

Species Act and/or the Marine Mammal Protection Act. ...........................................4-224

Table 4-14. Best Available Population Estimates for Marine Mammal Species in the Northern 

Gulf of Mexico. ...........................................................................................................4-229

Table 4-15. Commercial Fisheries Impact-Producing Factors......................................................4-313

Table 4-16. Landings Revenues: Landings Revenue by Species and State...............................4-315

Table 4-17. Recreational Fishing Impact Producing Factors........................................................4-323

Table 4-18. CPA and EPA Effort Data: Angler Trips in the Gulf of Mexico. ................................4-325

Table 4-19. CPA and EPA Catch Data: Fish Species Caught by Recreational Anglers from 

2008 through 2013 in Louisiana, Mississippi, and Alabama Combined....................4-327

Table 4-20. CPA and EPA Catch Data: Fish Species Caught by Recreational Anglers from 

2008 through 2013 in West Florida............................................................................4-327

Table 4-21. Texas Effort Data: Number of Angler Trips from 2009 through 2014.......................4-329

Table 4-22. Texas Catch Data: Top Species Landed by Recreational Fishermen. ....................4-330

Table 4-23. Recreational Resources Impact-Producing Factors..................................................4-338

Table 4-24. Recreational and Tourism Employment and Value-Added in BOEM's Economic 

Impact Areas in 2013. ................................................................................................4-340

Table 4-25. Archaeological Surveys and Resources Identified, 2009-2014.................................4-360

Table 4-26. Land Use and Coastal Infrastructure Impact-Producing Factors. .............................4-373

Table 4-27. Economic and Demographic Information for BOEM's Economic Impact Areas 

in 2015........................................................................................................................4-394

Table 4-28. Sales Volumes, Sales Values, and Revenues...........................................................4-397

Table 4-29. Cumulative Low: MAG-PLAN Industry Expenditure Impacts. ..................................4-403

Table 4-30. Cumulative High: MAG-PLAN Industry Expenditure Impacts...................................4-404

Table 4-31. Economic and Demographic Information for BOEM's Economic Impact Areas 

in 2050........................................................................................................................4-406

Table 4-32. Gulf of Mexico Single Low: MAG-PLAN Industry Expenditure Impacts. ..................4-408

Table 4-33. Gulf of Mexico Single High: MAG-PLAN Industry Expenditure Impacts. .................4-409

Table 4-34. CPA Single Low: MAG-PLAN Industry Expenditure Impacts...................................4-412

Table 4-35. CPA Single High: MAG-PLAN Industry Expenditure Impacts. .................................4-413

Table 4-36. WPA Single Low: MAG-PLAN Industry Expenditure Impacts. .................................4-415

Table 4-37. WPA Single High: MAG-PLAN Industry Expenditure Impacts. ................................4-417

Table B-1. Commonly Applied or “Standard” Mitigating Measures................................................ B-5
CHAPTER 5 

CONSULTATION AND COORDINATION

Consultation and Coordination 5-3 

What’s in This Chapter

• BOEM coordinated the prelease process with key agencies and organizations.

• The prelease and NEPA process has included the following to date: publication of the 

Notice of Intent to Prepare an EIS (NOI); the Call for Information (Call); and the Area 

Identification (Area ID) memorandum.

• BOEM conducted internal and public scoping to determine the content of this Multisale 

EIS.

− Ten comments were received during the scoping process.

− One comment was received in response to its Call.

• The USEPA (Regions 4 and 6) is a cooperating agency on this Multisale EIS.

• BOEM is undertaking consultation and other activities to comply with the following laws, 

including but not limited to, the following: the development of consistency determinations 

under the Coastal Zone Management Act (CZMA); consultation under the Endangered 

Species Act (ESA) for potential impacts to listed species or designated critical habitat; 

completion of an Essential Fish Habitat assessment pursuant to the Magnuson-Stevens 

Fishery Conservation and Management Act; and a request for comments and consultation 

with federally recognized Tribes pursuant to the National Historic Preservation Act and 

Executive Order 13175.

5 CONSULTATION AND COORDINATION

5.1 DEVELOPMENT OF THE PROPOSED ACTIONS

This Multisale EIS addresses 10 proposed regionwide Federal OCS oil and gas lease sales, 

as tentatively scheduled in the Proposed Program. BOEM conducted early coordination with 

appropriate Federal and State agencies and other concerned parties to discuss and coordinate the 

prelease process for the proposed GOM lease sales and this Multisale EIS. Key agencies and 

organizations included the FWS, NOAA, NOAA’s National Marine Fisheries Service, National Park 

Service, U.S. Coast Guard, U.S. Department of Defense, USEPA, State governors’ offices, federally 

recognized Indian Tribes, industry, and nongovernmental organizations. The timeline for 

coordination with these agencies and concerned parties throughout the development of this 

Multisale EIS is illustrated in Figure 5-1. 

Figure 5-1. Timeline for the Development of This Multisale EIS.
5-4 Gulf of Mexico Multisale EIS

5.2 NOTICE OF INTENT TO PREPARE AN EIS AND CALL FOR INFORMATION

On April 29, 2015, the Notice of Intent to Prepare an EIS (NOI) for the proposed regionwide 

lease sales was published in the Federal Register (2015c). Additional public notices, including 

individual consultation invitations to federally recognized Indian Tribes, were distributed via the U.S. 

Postal Service, local newspapers, and the Internet. A 30-day comment period was provided; it 

closed on June 1, 2015. Federal, State, and local governments, federally recognized Indian Tribes, 

nongovernmental organizations, other interested parties, and the public at large were invited to send 

written comments on the scope of the Multisale EIS to the Gulf of Mexico OCS Region. BOEM 

received 10 comment letters in response to the NOI. These comments are summarized below in 

Chapter 5.4.1. 

Pursuant to the Outer Continental Shelf Lands Act of 1953, as amended (OCSLA), BOEM 

published a Call for Information (Call) to request and gather information to determine the Area 

Identification (Area ID) for each proposed lease sale. The Call was published in the Federal 

Register (2015d) on September 4, 2015. The Call invited potential bidders to nominate areas of 

interest within the program area(s) included in the 2017-2022 Draft Proposed Program. The Call 

was also an opportunity for the public to provide information on environmental, socioeconomic, and 

other considerations relevant to determining the Area ID.

The comment period for the Call closed on October 5, 2015. BOEM received one comment 

letter in response to the Call from the Louisiana Department of Natural Resources. This comment is 

summarized below in Chapter 5.4.2. 

5.3 AREA ID MEMORANDUM

Using information provided in response to the Call and from scoping comments, BOEM then 

developed an Area ID recommendation memorandum. The Area ID is an administrative prelease 

step that describes the geographical area for environmental analysis and consideration for leasing. 

All of this information is being used to develop the proposed action and a reasonable range of 

alternatives for this Multisale EIS.

On November 20, 2015, the Area ID decision was made. One Area ID was prepared for all 

proposed lease sales. The Area ID memo recommended keeping the entire regionwide area of the 

GOM included in the Draft Proposed Program for consideration in this Multisale EIS. The area 

identified for lease includes all of the unleased blocks in the GOM not subject to Congressional 

moratorium pursuant to the Gulf of Mexico Energy Security Act of 2006.

5.4 DEVELOPMENT OF THE DRAFT MULTISALE EIS 

Scoping for the Draft Multisale EIS was conducted in accordance with CEQ regulations for 

implementing NEPA. Internal scoping provides BOEM an opportunity to update the BOEM Gulf of 

Mexico OCS Region’s environmental and socioeconomic information base. The internal scoping 

process for the Draft Multisale EIS yielded the following:
Consultation and Coordination 5-5 

• effort to make the document more reader-friendly by reducing the amount of text, 

optimizing the layout, and increasing the us e of graphics;

• a workshop was held for all subject-matter experts to reevaluate their resources 

and conclusions from prior lease sale EISs;

• several resources have been reorganized or renamed to increase document 

readability and reduce redundancies:

− Coastal Habitats (Estuarine Systems [Wetlands and Seagrasses/Submerged 

Vegetation] and Coastal Barrier Beaches and Associated Dunes);

− Deepwater Benthic Communities (Chemosynthetic Communities and 

Deepwater Coral Communities);

− Nonchemosynthetic Communities has been renamed to Deepwater Coral

Communities;

− Sargassum Communities was renamed Sargassum and Associated 

Communities;

− Live Bottom Habitats (Topographic Features and Pinnacles and Low-Relief 

Features);

− Invertebrate Resources were added to the resource description for Fishes 

(i.e., Fishes and Invertebrate Resources);

− Coastal and Marine Birds was renamed to Birds;

− Protected Species (Marine Mammals, Sea Turtles, Beach Mice, Protected 

Birds, and Protected Corals);

− Commercial Fisheries will be re-focused on industry trends as the biological 

aspects are being addressed in the Fishes and Invertebrate Resources 

chapter; and

− Social Factors (Demographics and Environmental Justice);

• after careful consideration, the diamondback terrapin was eliminated from further 

analysis as a species of special concern as they are neither listed as endangered 

nor threatened by the FWS nor are they likely to be impacted by a proposed 

action. Any potential impacts to diamondback terrapins would likely be as a 

result of their habitat location and, therefore, they are generally considered as 

part of the wetlands community. BOEM reserves the right to add them at a future 

date as designations and overall environmental indicators may change following 

consultations with, and concerns of, the FWS; but at present, their inclusion is 

not warranted since the potential for impacts are speculative at best; and
5-6 Gulf of Mexico Multisale EIS

• several white papers, which are incorporated by reference, were created and 

publicly released to reduce the amount of technical information contained in an 

EIS, such as the catastrophic spill event analysis, the description of essential fish 

habitats, and the OCS regulatory framework.

Public scoping provides those with an interest in the OCS Program an opportunity to provide 

comments on the proposed actions. Public scoping meetings were held in Texas, Louisiana, 

Mississippi, Alabama, and Florida on the following dates and at the times and locations indicated 

below:

Tuesday, April 12, 2015

1:00 p.m. CDT

Bureau of Ocean Energy Management

Gulf of Mexico OCS Region

1201 Elmwood Park Boulevard

New Orleans, Louisiana 70123

2 registered attendees

0 speakers

0 verbal comments received

0 written comments received

Thursday, April 14, 2015

1:00 p.m. CDT

Hilton Garden Inn Houston/Bush 

Intercontinental Airport

15400 John F. Kennedy Boulevard

Houston, Texas 77032

1 registered attendee

0 speakers

0 verbal comments received

0 written comments received

Tuesday May 19, 2015

6:00 p.m. CDT

Hilton Garden Inn Panama City

1101 US Highway 231

Panama City, Florida 32405

2 registered attendees

0 speakers

0 verbal comments received

0 written comments received

Wednesday May 20, 2015

3:00 p.m. CDT

Hilton Garden Inn Mobile West

828 West I-65 Service Road South

Mobile, Alabama 36609

1 registered attendee

0 speakers

0 verbal comments received

0 written comments received

Thursday May 21, 2015

3:00 p.m. CDT

Courtyard by Marriott

Gulfport Beachfront MS Hotel

1600 East Beach Boulevard

Gulfport, Mississippi 39501

1 registered attendee

0 speakers

0 verbal comments received

0 written comments received

5.4.1 Summary of Scoping Comments

In addition to accepting oral and written comments at each public meeting, BOEM accepted 

written comments by mail, email, and through the regulations.gov web portal 

(http://www.regulations.gov). BOEM received a total of 10 comments: 5 were mailed formal letters; 

3 were emails; and 2 were received through the regulations.gov web portal. Comments came from 
Consultation and Coordination 5-7 

Federal and State agencies, interest groups, industry, and the general public on the scope of the this

Multisale EIS, significant issues that should be addressed, alternatives that should be considered, 

and mitigating measures. Each comment was read and categorized according to its source and the 

nature of the information included. All scoping comments received that were relevant for a lease 

sale NEPA document were considered in the preparation of the Draft Multisale EIS. The scope and 

content of this Multisale EIS was formulated to ensure that the relevant issues and concerns 

expressed by stakeholders during the scoping process were fully addressed. Summaries of 

comments received follow.

United States Environmental Protection Agency, Regions 4 and 6 (letter dated September 8, 

2015)

• The USEPA formally requested Cooperating Agency status for this Multisale EIS. 

As a cooperating agency, the USEPA will

− provide expertise on NEPA compliance and other applicable subject matters;

− provide timely technical reviews and comments on preliminary documents, 

reports, analyses, and sections of the Draft and Final Multisale EISs;

− participate in meetings as resources allow;

− provide available information during preparation of the Draft and Final 

Multisale EISs in areas in which the USEPA has expertise; and

− review and comment on the Draft and Final Multisale EISs pursuant to 

USEPA regulatory responsibilities under Section 309 of the Clean Air Act.

Louisiana Department of Natural Resources, Office of Coastal Management (letter dated 

May 22, 2015)

• The Louisiana Office of Coastal Management requests that BOEM revisit the 

predictions of social and environmental effects on coastal resources made for 

earlier lease sales and compare them to existing environmental conditions.

• The State of Louisiana expressed that indirect and cumulative impacts to 

Louisiana’s coastal resources are not adequately addressed in previous EISs.

• The State of Louisiana is also concerned that Louisiana’s coastal wetlands are 

disproportionately bearing the impacts from OCS oil- and gas-related activities 

and requests compensatory mitigation.

• Louisiana supports the expansion of exploration and development of Gulf of 

Mexico energy resources.
5-8 Gulf of Mexico Multisale EIS

Louisiana Department of Culture, Recreation, and Tourism; State Historic Preservation Office 

(letter dated May 12, 2015)

• The Louisiana State Historic Preservation Office determined that the proposed 

actions will have no adverse effect on historic properties.

Florida Department of State, Division of Historical Resources (letter dated April 15, 2015 and 

email dated May 12, 2015)

• The State of Florida determined that BOEM’s proposed 2017-2022 GOM lease 

sales will have no effect on historic properties but requested to be notified if any 

cultural resources are identified (April 15, 2015).

• Florida clarified that they are primarily interested in resources that are identified 

off Florida that cannot be avoided (May 12, 2015).

Alabama Historical Commission (letter dated April 30, 2015)

• The State of Alabama agreed that the proposed phased approach to meeting 

Section 106 requirements is reasonable and appropriate for the proposed 

actions. 

Conoco Philips (email dated April 28, 2015)

• Conoco Philips recommends that this Multisale EIS address the effects of the 

GOM lease sales using alternatives that are formulated to mitigate known risks or 

adverse impacts.

• BOEM must try to reach an appropriate balance of all oil and gas exploration and 

production, environmental protection, and potential impacts to coastal zone 

factors when implementing the Five-Year Program.

• BOEM should apply its best available scientific analysis to operating scenarios 

that accurately reflects actual OCS oil- and gas-related activities that occur on a 

day-to-day basis.

• Conoco Philips opposes the use of mitigations based on the use of dated 

technologies for new studies or the reapplication of findings from previous 

studies that used out-of-date technology, as well as the use of studies outside 

normal parameters of oil and gas development.

The American Petroleum Institute (email dated May 29, 2015)

• The American Petroleum Institute recommends that the Multisale EIS be 

designed specifically with the idea that it will be used as a reference for future 

NEPA analysis.
Consultation and Coordination 5-9 

• BOEM should consider the extensive safety improvements implemented by 

industry and new requirements imposed on offshore operations since the 

Deepwater Horizon explosion, oil spill, and response, particularly the formation of 

many well containment companies and their ability to assist in any potential 

future incidents.

Save the Manatee Club (regulations.gov submission dated May 29, 2015)

• The Save the Manatee Club requests NEPA analysis of the EPA in a separate 

process.

• The Multisale EIS analysis should assess the impacts from all aspects of 

offshore oil and gas development and the cultural value of resources, and it 

should differentiate the risks of deepwater drilling from those of less 

technologically difficult operations.

• BOEM should analyze an alternative that includes a buffer around the portions of 

the EPA that are under Congressional Moratorium.

Center for Biological Diversity (regulations.gov submission dated May 29, 2015)

• The Center for Biological Diversity asked BOEM to delay leasing until after the 

effects of the Deepwater Horizon explosion, oil spill, and response are known 

and the ecosystem has recovered.

• The Multisale EIS should consider the direct, indirect, and cumulative impacts of 

oil spills, including catastrophic spills, and consider the science that has been 

released since the Deepwater Horizon explosion, oil spill, and response.

• BOEM must also analyze the direct, indirect, and cumulative effects of oil and 

gas activities, particularly air, water, noise, and light pollution, and increased 

vessel traffic in relation to sensitive biological resources.

• The Center for Biological Diversity requested that BOEM consider the impacts of 

offshore fracking and a reasonable range of alternatives.

Jean Public (email dated April 29, 2015)

• Jean Public opposes the proposed actions due to the lack of safety changes 

since the Deepwater Horizon explosion, oil spill, and response.

5.4.2 Summary of Comments Received in Response to the Call for Information

In response to the Call, BOEM received one letter from the Louisiana Department of Natural 

Resources.
5-10 Gulf of Mexico Multisale EIS

Louisiana Department of Natural Resources, Office of Coastal Management (letter dated 

September 29, 2015) 

• The Louisiana Office of Coastal Management requests that BOEM consider 

secondary and cumulative impacts of OCS lease sales on coastal environments.

• BOEM should identify, quantify, and mitigate (e.g., compensatory mitigation) 

secondary and cumulative harm that occurs to Louisiana’s coastal wetlands.

• BOEM should implement plans for validating predictions of social and 

environmental effects on coastal resources.

• Offshore exploration and development of hydrocarbon resources has been and 

continues to be of significant value to Louisiana and coastal communities.

5.4.3 Additional Public Input Opportunities

Although scoping is a formal, defined process initiated by the publication of the NOI and Call 

with an identified closing date, public input and other coordination meetings continue to proceed 

throughout this NEPA process. Public input and coordination opportunities were also available 

during BOEM’s requests for information, comments, input, and review of its other NEPA documents, 

including the following:

• Request for Information on the 2017-2022 Outer Continental Shelf Oil and Gas 

Leasing: Draft Proposed Program; 

• Notice of Availability for the 2017-2022 Outer Continental Shelf Oil and Gas 

Leasing: Draft Proposed Program; and

• Scoping for the 2017-2022 Five-Year Program EIS.

Comments from these additional public input opportunities are incorporated, where relevant, 

in the Multisale EIS through the tiering process. One comment from the NPS was identified by 

BOEM’s 2017-2022 Programmatic EIS project team as more relevant to a regional NEPA review. 

Therefore, it was considered during the preparation of this Multisale EIS. The NPS comment 

requested an exclusion zone south and within 15 mi (24 km) of the Mississippi portion of the Gulf 

Islands National Seashore.

5.4.4 Cooperating Agencies

According to Part 516 of the DOI Departmental Manual, BOEM must invite eligible 

government entities to participate as cooperating agencies when developing an EIS in accordance 

with the requirements of NEPA and CEQ regulations. BOEM must also consider any requests by 

eligible government entities to participate as a cooperating agency with respect to a particular EIS, 

and must either accept or deny such requests.
Consultation and Coordination 5-11

The NOI, which was published on April 29, 2015, included an invitation to other Federal 

agencies and State, Tribal, and local governments to consider becoming cooperating agencies in the 

preparation of this Multisale EIS. In a letter dated September 8, 2015, USEPA Regions 4 and 6 

requested cooperating agency status for the Multisale EIS. On December 16, 2015, a Memorandum 

of Agreement between BOEM and USEPA Regions 4 and 6 was initiated, which defines the roles 

and responsibilities for each agency (Appendix C).

5.5 DISTRIBUTION OF THE DRAFT MULTISALE EIS FOR REVIEW AND COMMENT

BOEM will send copies of the Draft Multisale EIS to the government, public, and private 

agencies and groups listed below. Local libraries along the Gulf Coast will be provided copies of this 

document; a list of these libraries is available on BOEM’s website at http://www.boem.gov/

nepaprocess/. 

Federal Agencies

Congress

Congressional Budget Office

House Resources Subcommittee on Energy 

and Mineral Resources

Senate Committee on Energy and Natural 

Resources

Department of Commerce

National Oceanic and Atmospheric 

Administration

National Marine Fisheries Service

Department of Defense

Department of the Air Force

Department of the Army

Corps of Engineers

Department of the Navy

Naval Mine and Anti-Submarine Warfare 

Command

Department of Energy

Strategic Petroleum Reserve PMD

Department of Homeland Security

U.S. Coast Guard

Department of State

Bureau of Oceans and International 

Environmental and Scientific Affairs

Department of the Interior

Bureau of Ocean Energy Management

Bureau of Safety and Environmental 

Enforcement

Fish and Wildlife Service

Geological Survey

National Park Service

Office of Environmental Policy and 

Compliance

Office of the Solicitor

Department of Transportation

Pipeline and Hazardous Materials Safety 

Administration

Office of Pipeline Safety

Environmental Protection Agency

Region 4

Region 6

Marine Mammal Commission

State and Local Agencies

Alabama

Governor’s Office

Alabama Highway Department

Alabama Historical Commission and State 

Historic Preservation Officer

Alabama Public Library Service

Alabama Public Service Commission

City of Mobile

City of Montgomery

Department of Conservation and Natural 

Resources

Department of Environmental Management

Geological Survey of Alabama

South Alabama Regional Planning 

Commission

State Legislature Natural Resources 

Committee

Town of Dauphin Island

Florida

Governor’s Office

Bay County

Citrus County

City of Destin

City of Fort Walton Beach
5-12 Gulf of Mexico Multisale EIS

City of Gulf Breeze

City of Panama City

City of Pensacola

Department of Agriculture and Consumer 

Services

Department of Environmental Protection

Department of State Archives, History and 

Records Management

Escambia County

Florida Emergency Response Commission

Florida Fish and Wildlife Conservation 

Commission

Franklin County

Gulf County

Hernando County

Hillsborough City-County Planning 

Commission

Lee County

Monroe County

North Central Florida Regional Planning 

Council

Okaloosa County

Pasco County

Santa Rosa County

Sarasota County

Southwest Florida Regional Planning 

Council

State Legislature Agriculture and Natural 

Resources Committee

Tampa Bay Regional Planning Council

Walton County

West Florida Regional Planning Council

Withlacoochee Regional Planning Council

Louisiana

Governor’s Office

Calcasieu Parish

Cameron Parish

City of Grand Isle

City of Lake Charles

City of Morgan City

City of New Orleans

Department of Culture, Recreation, and 

Tourism

Department of Economic Development

Department of Environmental Quality

Department of Natural Resources

Department of Transportation and 

Development

Department of Wildlife and Fisheries

Houma-Terrebonne Chamber of Commerce

Jefferson Parish Director

Jefferson Parish President

Lafourche Parish Coastal Zone 

Management

Lafourche Parish Water District #1

Louisiana Geological Survey

South Lafourche Levee District

St. Bernard Planning Commission

State House of Representatives, Natural 

Resources Committee

State Legislature, Natural Resources 

Committee

State of Louisiana Library

Terrebonne Parish

Mississippi

Governor’s Office

City of Bay St. Louis

City of Gulfport

City of Pascagoula

Department of Archives and History

Department of Environmental Quality

Department of Marine Resources

Department of Wildlife, Fisheries, and Parks

Jackson-George Regional Library System

Mississippi Development Authority

State Legislature Oil, Gas, and Other 

Minerals Committee

Texas

Governor’s Office

Aransas Pass Public Library

Attorney General of Texas

Chambers County Library System

City of Lake Jackson

General Land Office

Southeast Texas Regional Planning 

Commission

State Legislature Natural Resources 

Committee

State Senate Natural Resources Committee

Texas Historical Commission

Texas Legislation Council

Texas Parks and Wildlife Department

Texas Sea Grant

Texas State Library and Archives

Texas Water Development Board

Federally Recognized Indian Tribes

Alabama-Coushatta Tribe of Texas

Caddo Nation of Oklahoma

Chitimacha Tribe of Louisiana

Choctaw Nation of Oklahoma
Consultation and Coordination 5-13

Coushatta Tribe of Louisiana

Jena Band of Choctaw Indians

Miccosukee Tribe of Indians of Florida

Mississippi Band of Choctaw Indians

Poarch Band of Creek Indians

Seminole Tribe of Florida

Seminole Nation of Oklahoma

Tunica-Biloxi Indian Tribe of Louisiana

Industry

Adams and Reese, LLP

Alabama Petroleum Council

American Petroleum Institute

Applied Technology Research Corporation

Area Energy LLC

Associated Gas Distributors of Florida 

Baker Atlas

Baker Energy

Bepco, Inc.

C.H. Fenstermaker & Associates, Inc.

Century Exploration N.O., Inc.

Chet Morrison Contractors

Chevron U.S.A. Inc.

C-K Associates, LLC

Coastal Conservation Association

Coastal Environments, Inc.

Columbia Gulf Transmission

Continental Shelf Associates, Inc.

De Leon & Associates

Ecological Associates, Inc.

Ecology and Environment

Ecosystem Management, Inc.

Energy Partners, Ltd.

EOG Resources, Inc.

Exxon Mobil Production Company

Florida Natural Gas Association

Florida Petroleum Council

Florida Power and Light

Florida Propane Gas Association

Freeport-McMoRan, Inc.

General Insulation, Inc.

Global Industries, Ltd.

Gulf of Mexico Newsletter

Halliburton Corporation

Han & Associates, Inc.

Horizon Marine, Inc.

Industrial Vehicles International, Inc.

J. Connor Consultants

John Chance Land Surveys, Inc.

L&M Botruc Rental, Inc.

Lampl Herbert Consultants

Larose Intercoastal Lands, Inc.

Linder Oil Company

Louisiana Oil and Gas Association 

Magnum Steel Services Corp.

Marine Safety Office

Mid Continent Oil and Gas Association

Nature’s Way Marine, LLC

Newfield Exploration Company

Offshore Process Services, Inc.

Oil and Gas Property Management, Inc.

Phoenix International Holdings, Inc. 

Project Consulting Services

R.B. Falcon Drilling

Raintree Resources, Inc.

Science Applications International 

Corporation

Seneca Resources Corporation

SEOT, Inc.

Shell Exploration & Production Company

Shell Offshore, Inc.

Stone Energy Corporation

Strategic Management Services-USA

T. Baker Smith, Inc.

Texas Geophysical Company, Inc.

The SJI, LLC

The Times-Picayune

The Washington Post

URS Corporation

W & T Offshore, Inc.

Waring & Associates

WEAR-TV

Special Interest Groups

1000 Friends of Florida

Alabama Oil & Gas Board

Alabama Nature Conservancy

Alabama Wildlife Federation

American Cetacean Society

Apalachee Regional Planning Council

Apalachicola Riverkeeper

Audubon Louisiana Nature Center

Audubon of Florida

Barataria-Terrebonne National Estuary 

Program

Bay County Chamber of Commerce

Bay Defense Alliance 

Capital Region Planning Commission

Center for Marine Conservation

Citizens Association of Bonita Beach

Clean Gulf Associates

Coalition to Restore Coastal Louisiana
5-14 Gulf of Mexico Multisale EIS

Coastal Conservation Association

Concerned Shrimpers of America

Conservancy of Southwest Florida

Earthjustice

Florida Chamber of Commerce

Florida Natural Area Inventory

Florida Wildlife Federation 

Gulf and South Atlantic Fisheries 

Foundation, Inc.

Gulf Coast Environmental Defense

Gulf Coast Fisherman’s Coalition

Gulf Restoration Network

Houma-Terrebonne Chamber of Commerce

LA 1 Coalition, Inc.

League of Women Voters of the Pensacola 

Bay Area

Louisiana Wildlife Federation

Manasota-88

Marine Mammal Commission

Mobile Bay National Estuary Program

Natural Resources Defense Council

Nature Conservancy

Offshore Operators Committee

Organized Fishermen of Florida

Panama City Beach Convention and Visitors 

Bureau

Pensacola Archaeological Society

Perdido Key Association

Perdido Key Chamber of Commerce 

Perdido Watershed Alliance

Restore or Retreat

Roffers Ocean Fishing Forecast Service

Save the Manatee Club

Sierra Club

South Central Industrial Association

Surfrider Foundation

The Nature Conservancy

The Ocean Conservancy

Ports/Docks 

Alabama

Alabama State Port Authority

Port of Mobile

Florida

Manatee County Port Authority

Panama City Port Authority

Port of Pensacola

Port St. Joe Port Authority

Tampa Port Authority

Louisiana

Abbeville Harbor and Terminal District

Grand Isle Port Commission

Greater Baton Rouge Port Commission

Greater Lafourche Port Commission

Lake Charles Harbor and Terminal District

Plaquemines Port, Harbor and Terminal 

District 

Port of Baton Rouge

Port of Iberia District

Port of New Orleans

Twin Parish Port Commission

St. Bernard Port, Harbor and Terminal 

District 

West Cameron Port Commission

Mississippi

Mississippi State Port Authority

Texas

Brownsville Navigation District—Port of 

Brownsville

Port Freeport

Port Mansfield/Willacy County Navigation 

District 

Port of Beaumont

Port of Corpus Christi Authority

Port of Galveston

Port of Houston Authority

Port of Isabel—San Benito Navigation 

District 

Port of Port Arthur Navigation District

Educational Institutions/Research Laboratories

Abilene Christian University

Dauphin Island Sea Laboratory

Florida A&M University

Florida Institute of Oceanography

Florida Institute of Technology

Florida Sea Grant College

Florida State University

Foley Elementary School

Gulf Coast Research Laboratory

Gulf Coast State College

Harbor Branch Oceanography

Louisiana Sea Grant College Program

Louisiana State University

Louisiana Tech University

Louisiana Universities Marine Consortium

Loyola University

McNeese State University
Consultation and Coordination 5-15

Mississippi State University

Mississippi-Alabama Sea Grant Consortium

Mote Marine Laboratory

Nicholls State University

Pensacola Junior College

Tulane University

University of Alabama

University of Florida

University of Louisiana at Lafayette

University of Miami

University of Mississippi 

University of New Orleans

University of South Alabama

University of South Florida

University of Southern Mississippi

University of Texas at Arlington

University of Texas at Austin

University of Texas Law School

University of Texas Libraries

University of West Florida

5.6 COASTAL ZONE MANAGEMENT ACT

The Federal agency performs a consistency review pursuant to the Coastal Zone 

Management Act (CZMA), and CDs are prepared for each coastal State with a federally approved 

Coastal Management Plan prior to each of the proposed lease sales. To prepare the CDs, BOEM 

reviews each State’s approved Coastal Management Plan and analyzes the potential impacts as 

outlined in this Multisale EIS, new information, and applicable studies as they pertain to the 

enforceable policies of each Coastal Management Program (CMP). The CZMA requires that 

Federal actions that are reasonably likely to affect any land or water use or natural resource of the 

coastal zone be “consistent to the maximum extent practicable” with relevant enforceable policies of 

the State’s federally approved coastal management program (15 CFR part 930 subpart C).

Based on these and other analyses, BOEM’s Gulf of Mexico OCS Region’s Regional 

Director makes an assessment of consistency, which is then sent to the States of Texas, Louisiana, 

Mississippi, Alabama, and Florida for proposed regionwide lease sales; to Texas and Louisiana for 

proposed WPA lease sales; or Louisiana, Mississippi, Alabama, and Florida for proposed CPA 

and/or EPA lease sales. If the State concurs, BOEM can proceed with the proposed lease sale. A 

State’s concurrence may be presumed when a State does not provide a response within the 60-day 

review period. A State may request an extension of time to review the CD within the 60-day period, 

which the Federal agency shall approve for an extension of 15 days or less. If a State objects, it 

must do the following under the CZMA:

(1) indicate how BOEM’s prelease proposal is inconsistent with the State’s federally 

approved CMP and suggest alternative measures to bring BOEM’s proposal into 

consistency with the State’s CMP; or

(2) describe the need for additional information that would allow a determination of 

consistency. In the event of an objection, the Federal and State agencies should 

use the remaining portion of the 90-day review period to attempt to resolve their 

differences (15 CFR § 930.43(b)).

At the end of the 90-day review period, the Federal agency shall not proceed with the activity 

over a State agency’s objection unless the Federal agency concludes that, under the “consistent to 

the maximum extent practicable” standard described in 15 CFR § 930.32, consistency with the 
5-16 Gulf of Mexico Multisale EIS

enforceable policies of the CMP is prohibited by existing law applicable to the Federal agency and 

the Federal agency has clearly described, in writing, to the CZMA State agency the legal 

impediments to full consistency; or, the Federal agency has concluded that its proposed action is 

fully consistent with the enforceable policies of the CMP, though the State agency objects. Unlike 

the consistency process for specific OCS plans and permits, there is no procedure for administrative 

appeal to the Secretary of Commerce for a Federal CD for prelease activities. In the event that there 

is a serious disagreement between BOEM and a State, either agency may request mediation. 

Mediation is voluntary, and the Secretary of Commerce would serve as the mediator. Whether there 

is mediation or not, the final CD is made by DOI, and it is the final administrative action for the 

prelease consistency process. Each Gulf State’s CMP is described in Appendix G. 

5.7 ENDANGERED SPECIES ACT

The Endangered Species Act of 1973 (16 U.S.C. §§ 1531 et seq.) establishes a national 

policy designed to protect and conserve threatened and endangered species and the ecosystems 

upon which they depend. BOEM and BSEE are currently in consultation with NMFS and FWS 

regarding the OCS oil and gas program in the Gulf of Mexico. BOEM is acting as the lead agency in 

the ongoing consultation, with BSEE’s assistance and involvement. The programmatic consultation, 

which was reinitiated in 2010, was expanded in scope after the reinitiation of consultation by BOEM 

following the Deepwater Horizon explosion and oil spill, and it will include both existing and future 

OCS oil and gas leases in the Gulf of Mexico over a 10-year period. This consultation also 

considers any changes in baseline environmental conditions following the Deepwater Horizon 

explosion, oil spill, and response. The programmatic consultation will also include postlease 

activities associated with OCS oil- and gas-related activities in the Gulf of Mexico, including G&G 

and decommissioning activities. While the programmatic Biological Opinion is in development, 

BOEM and NMFS have agreed to interim consultations on postlease approvals.

With consultation ongoing, BOEM and BSEE will continue to comply with all reasonable and 

prudent measures and the terms and conditions under the existing consultations, along with 

implementing the current BOEM- and BSEE-required mitigation, monitoring, and reporting 

requirements. Based on the most recent and best available information at the time, BOEM and 

BSEE will also continue to closely evaluate and assess risks to listed species and designated critical 

habitat in upcoming environmental compliance documentation under NEPA and other statutes.

5.8 MAGNUSON-STEVENS FISHERY CONSERVATION AND MANAGEMENT ACT

Pursuant to Section 305(b) of the Magnuson-Stevens Fishery Conservation and 

Management Act, Federal agencies are required to consult with the NMFS on any action that may 

result in adverse effects to EFH. The NMFS published the final rule implementing the EFH 

provisions of the Magnuson-Stevens Fisheries Conservation and Management Act (50 CFR 

part 600) on January 17, 2002. Certain OCS oil- and gas-related activities authorized by BOEM may 

result in adverse effects to EFH and therefore require EFH consultation.
Consultation and Coordination 5-17

BOEM prepared an EFH Assessment that describes the OCS proposed activities, analyzes 

the effects of the proposed activities on EFH, and identifies proposed mitigating measures (USDOI, 

BOEM, 2016d). The programmatic EFH consultation covers proposed lease sales analyzed in this 

Multisale EIS and related activities (i.e., decommissioning and geological and geophysical). The 

EFH Assessment and the formalized conservation recommendations put forth by the NMFS and 

accepted by BOEM complete the EFH consultation. While the necessary components of the EFH 

consultation are complete (as per BOEM’s June 8, 2012, response letter to the NMFS), there is 

ongoing coordination among NMFS, BOEM, and BSEE. This coordination includes annual reports 

from BOEM to the NMFS, meetings with regional staff, and discussions of mitigation and relevant 

topics. All agencies will continue to communicate for the duration of the EFH consultation 

(2017-2022).

5.9 NATIONAL HISTORIC PRESERVATION ACT

In accordance with the National Historic Preservation Act (54 U.S.C. §§ 300101 et seq.), 

Federal agencies are required to consider the effect of their undertakings on historic properties. The 

implementing regulations for Section 106 of the National Historical Preservation Act, issued by the 

Advisory Council on Historic Preservation (36 CFR part 800), specify the required review process. 

Because of the extensive geographic area analyzed in this Multisale EIS and because there will be 

no adverse effects to historic properties as a result of the proposed actions, BOEM will complete its 

Section 106 review process once BOEM has performed the necessary site-specific analysis of 

postlease permitted or approved activities. Additional consultations with the Advisory Council on 

Historic Places, State Historic Preservation Offices, federally recognized Indian Tribes, and other 

consulting parties may take place at that time, if appropriate. Refer to Chapter 4.13 for more 

information on this review process.

As an early planning effort, BOEM initiated a request for comment on the NOI for the 

Multisale EIS via a formal letter to each of the affected Gulf Coast States on April 3, 2015. A 30-day 

comment period was provided. The State Historic Preservation Officers for Alabama, Florida, and 

Louisiana responded via formal letters, all concurring that no historic properties will be affected. The 

Florida State Historic Preservation Officer further requested to be notified and given the opportunity 

to comment should any cultural resources be identified off the Florida coast. No additional 

responses were received.

BOEM also solicited Tribal comment on the 2017-2022 Outer Continental Shelf Oil and Gas 

Leasing: Draft Proposed Program via a formal letter on March 4, 2015. That letter was addressed 

to each of the Gulf Coast State-affiliated federally recognized Indian Tribes, including the AlabamaCoushatta Tribe of Texas, Caddo Nation of Oklahoma, Chitimacha Tribe of Louisiana, Choctaw 

Nation of Oklahoma, Coushatta Tribe of Louisiana, Jena Band of Choctaw Indians, Miccosukee 

Tribe of Indians of Florida, Mississippi Band of Choctaw Indians, Poarch Band of Creek Indians, 

Seminole Tribe of Florida, Seminole Nation of Oklahoma, and Tunica-Biloxi Indian Tribe of 

Louisiana. No comments or requests to consult have yet been received; however, BOEM continues
5-18 Gulf of Mexico Multisale EIS

to invite Tribal consultation on all of its activities and will be responsive to any Tribal concerns that 

may arise.

Historic Preservation Fund

In 1977 the Historic Preservation Fund (54 U.S.C. §§ 303101-303103) was established to 

assist State and Tribal Historic Preservation Officers in their efforts to protect and preserve historic 

properties as set forth in the requirements of the National Historic Preservation Act. The Historic 

Preservation Fund is authorized at $150 million per year and is fully funded from OCS oil and gas 

revenues payable to the United States under Section 9 of the OCSLA (43 U.S.C. § 1338). However, 

these funds are available for expenditure only when appropriated by Congress, which has never fully 

appropriated the available funds. Since inception, approximately $3.3 billion of the Historic 

Preservation Fund remains unappropriated (National Conference of State Historic Preservation 

Officers, 2015).

The Historic Preservation Funds’ monies may be used directly by State Historic Preservation 

Officers/Tribal Historic Preservation Officers or passed on as subgrants and contracts to public and 

private agencies, nonprofit organizations, educational institutions, and individuals. Eligible 

preservation projects include historic properties’ survey and inventory, National Register of Historic 

Places’ nominations, preservation education, architectural planning, historic structure reports, 

community preservation planning, and brick and mortar repairs to buildings (USDOI, NPS, 2014). 

These historic preservation programs can further catalyze community and neighborhood 

revitalization, job creation, and economic development, primarily through heritage tourism and the 

rehabilitation of historic properties through the Historic Tax Credit, which is administered by State 

Historic Preservation Officers. Since the Historic Preservation Fund was implemented in 1977, the 

Historic Tax Credit program nationwide has rehabilitated nearly 39,000 buildings, created 2.4 million 

jobs, created 140,000 low- and moderate-income housing units, and leveraged $109 billion in nonFederal investment (National Conference of State Historic Preservation Officers, 2014; USDOI, 

NPS, 2014). In FY 2015, Congress allocated a total of $56.41 million from the Historic Preservation 

Fund, of which $46.925 million was awarded to State Historic Preservation Officers and 

$8.985 million was awarded to Tribal Historical Preservation Officers. An additional $500,000 was 

awarded for projects that will increase diversity in the National Register of Historic Places and the 

National Historic Landmarks Programs (National Conference of State Historic Preservation Officers, 

2015).

5.10 GOVERNMENT-TO-GOVERNMENT

In accordance with Executive Order 13175, “Consultation and Coordination with Indian Tribal 

Governments,” Federal agencies are required to establish regular and meaningful consultation and 

collaboration with Tribal officials in the development of Federal policies that have Tribal implications 

to strengthen the United States’ government-to-government relationships with Indian Tribes, and to 

reduce the imposition of unfunded mandates upon Indian Tribes. On March 4, 2015, BOEM sent a 

formal letter to federally recognized Indian Tribes notifying them of the development of the 2017-

2022 Outer Continental Shelf Oil and Gas Leasing Draft Proposed Program and the Gulf of Mexico 
Consultation and Coordination 5-19

Geological and Geophysical Activities Programmatic EIS. That letter was addressed to each of the 

Gulf Coast State-affiliated Indian Tribes, including the Alabama-Coushatta Tribe of Texas, Caddo

Nation of Oklahoma, Chitimacha Tribe of Louisiana, Choctaw Nation of Oklahoma, Coushatta Tribe 

of Louisiana, Jena Band of Choctaw Indians, Miccosukee Tribe of Indians of Florida, Mississippi 

Band of Choctaw Indians, Poarch Band of Creek Indians, Seminole Tribe of Florida, Seminole 

Nation of Oklahoma, and Tunica-Biloxi Indian Tribe of Louisiana. The letter was intended to be the 

first step of a long-term and broad consultation effort between BOEM and the Gulf-area Tribes, 

inclusive of all BOEM activities that may occur under the Draft Proposed Program, as well as 

ongoing activities. As of this writing, no formal responses have been received in response to the 

March 4, 2015, letter; however, informal discussions with designated Tribal representatives are 

ongoing to determine if any of the individual Tribes desire continued consultations on these issues.

The Poarch Band of Creek Indians has indicated that they do not have any specific concerns 

with BOEM’s activities on the OCS, but they would like to continue to receive notifications on 

BOEM’s activities (McCullers, official communication, 2015). Additionally, the Jena Band of 

Choctaw has indicated a general concern over adverse effects to documented or undocumented 

prehistoric and historic sites in the CPA and requests to be notified should such effects occur, as 

well as to continue being notified on BOEM’s activities (Shively, official communication, 2015a and 

2015b).

BOEM has also analyzed environmental justice issues for minority and low-income 

populations, which is broadly applicable to federally recognized Indian Tribes. Further information 

on that analysis can be found in Chapter 4.14.3.3. 

CHAPTER 6 

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CHAPTER 7 

PREPARERS

Preparers 7-3 

7 PREPARERS

Gary D. Goeke, Chief, Environmental Assessment Section

Tershara Matthews, Unit Supervisor, Environmental Protection Specialist

Helen Rucker, NEPA Coordinator, Environmental Scientist

Ross Del Rio, NEPA Co-Coordinator, Environmental Scientist

Mary Cody, Headquarters’ Coordinator, Environmental Protection Specialist

Robert Arpino, Physical Scientist

Bruce Baird, Biologist

Mark Belter, Marine Biologist 

Idrissa Boube, Environmental Scientist

Darice K. Breeding, Environmental Protection Specialist

Brian Cameron, Senior Environmental Scientist

Alicia Caporaso, Marine Archaeologist

Sindey Chaky, Social Scientist

Leonard Coates, Supervisor, Mapping and Automation Section

Thierry DeCort, Chief, Geological and Geophysical Section

Chris DuFore, Oceanographer

Stephanie Gambino, Chief, Biological/Social Sciences Section

Donald (Tre) W. Glenn III, Protected Species Biologist

Mike Gravois, Geographer

Allison Hernandez, Protected Species Biologist

Jose Hernandez, Physical Scientist

Nikki Hughes, Protected Species Biologist

Jack Irion, Unit Supervisor, Marine Archaeologist

Mark Jensen, Economist

Matthew Johnson, Marine Biologist

Douglas Jones, Senior Marine Archaeologist

Agatha-Marie Kaller, Unit Supervisor, Marine Biologist

Ariel Kay, Environmental Scientist

Paula (Kaye) London, Protected Species Biologist

Christopher Lopinto, Data Quality Analyst

Charles (Jay) McCreery, Physical Scientist

Stacie Merritt, Physical Scientist

Margaret Metcalf, Chief, Physical/Chemical Sciences Section

Deborah Miller, Technical Editor

David P. Moran, Biologist

Mark Mueller, Marine Ecologist

Trevis Olivier, Environmental Scientist

Christopher Oos, Geographer

S. Erin O’Reilly, Physical Scientist

Catherine Rosa, Environmental Assessment Program Specialist

Shane Stradley, Geographer

Toby Wraye, Information Management Specialist

CHAPTER 8 

GLOSSARY

Glossary 8-3 

8 GLOSSARY 

Acute—Sudden, short term, severe, critical, 

crucial, intense, but usually of short 

duration, as opposed to chronic. Effects 

associated with acute can vary depending 

on the context of its use (e.g., acute 

[short-term] exposure could be more or less 

problematic than chronic [long-term] 

exposure).

Anaerobic—Capable of growing in the absence 

of molecular oxygen.

Annular preventer—A component of the 

pressure control system in the BOP that 

forms a seal in the annular space around 

any object in the wellbore or upon itself, 

enabling well control operations to 

commence.

Anthropogenic—Coming from human sources, 

relating to the effect of humankind on 

nature.

Antipatharian Transitional Zone—The area 

located between 50 and 90 m (164 and 

295 ft), where available light is reduced and 

there is a gradual ecosystem change from 

tropical shallow-water corals that are 

dependent on light to deeper water species, 

such as antipatharian black corals that are 

not.

API gravity—A standard adopted by the 

American Petroleum Institute for expressing 

the specific weight of oil.

Aromatic—Class of organic compounds 

containing benzene rings or benzenoid 

structures. 

Attainment area—An area that is shown by 

monitored data or by air-quality modeling 

calculations to be in compliance with 

primary and secondary ambient air quality 

standards established by the USEPA.

Barrel (bbl)—A volumetric unit used in the 

petroleum industry; equivalent to 42 U.S. 

gallons or 158.99 liters.

Benthic—On or in the bottom of the sea.

Biological Opinion—The FWS or NMFS 

evaluation of the impact of a proposed 

action on endangered and threatened 

species, in response to formal consultation 

under Section 7 of the Endangered Species 

Act.

Block—A geographical area portrayed on 

official BOEM protraction diagrams or 

leasing maps that contains approximately 

5,760 ac (2,331 ha; 9 mi2

).

Blowout—An uncontrolled flow of fluids below 

the mudline from appurtenances on a 

wellhead or from a wellbore.

Blowout preventer (BOP)—One of several 

valves installed at the wellhead to prevent 

the escape of pressure either in the annular 

space between the casing and drill pipe or 

in open hole (i.e., hole with no drill pipe) 

during drilling completion operations. 

Blowout preventers on jackup or platform 

rigs are located at the water’s surface; on 

floating offshore rigs, BOPs are located on 

the seafloor.

Bottom kill—A wild well-control procedure 

involving the intersection of an uncontrolled 

well with a relief well for the purpose of 

pumping heavy mud or cement into the wild 

well to stanch the flow of oil or gas (the wellcontrol strategy for the Macondo spill 

deployed in mid-July 2010 that resulted in 

the successful capping of the well).

Cetacean—Aquatic mammal of the order 

Cetacea, such as whales, dolphins, and 

porpoises.
8-4 Gulf of Mexico Multisale EIS

Chemosynthetic—Organisms that obtain their 

energy from the oxidation of various 

inorganic compounds rather than from light 

(photosynthetic).

Coastal waters—Waters within the 

geographical areas defined by each State’s 

Coastal Zone Management Program.

Coastal wetlands—forested and nonforested 

habitats, mangroves, and marsh islands 

exposed to tidal activity. These areas 

directly contribute to the high biological 

productivity of coastal waters by input of 

detritus and nutrients, by providing nursery 

and feeding areas for shellfish and finfish, 

and by serving as habitat for birds and other 

animals.

Coastal zone—The coastal waters (including 

the lands therein and thereunder) and the 

adjacent shorelands (including the waters 

therein and thereunder) strongly influenced 

by each other and in proximity to the 

shorelines of several coastal states; the 

zone includes islands, transitional and 

intertidal areas, salt marshes, wetlands, and 

beaches, and it extends seaward to the 

outer limit of the United States territorial 

sea. The zone extends inland from the 

shorelines only to the extent necessary to 

control shorelands, the uses of which have 

a direct and significant impact on the coastal 

waters. Excluded from the coastal zone are 

lands the use of which is by law subject to 

the discretion of or which is held in trust by 

the Federal Government, its officers, or 

agents (also refer to State coastal zone 

boundaries).

Completion—Conversion of a development 

well or an exploration well into a production 

well.

Condensate—Liquid hydrocarbons produced 

with natural gas; they are separated from 

the gas by cooling and various other means. 

Condensates generally have an API gravity 

of 50°-120° 

Continental margin—The ocean floor that lies 

between the shoreline and the abyssal 

ocean floor, includes the continental shelf, 

continental slope, and continental rise.

Continental shelf—General term used by 

geologists to refer to the continental margin 

province that lies between the shoreline and 

the abrupt change in slope called the shelf 

edge, which generally occurs in the Gulf of 

Mexico at about the 200-m (656-ft) water 

depth. The continental shelf is 

characterized by a gentle slope (about 0.1°). 

This is different from the juridical term used 

in Article 76 of the United Nations 

Convention on the Law of the Sea Royalty 

Payment (refer to the definition of Outer 

Continental Shelf).

Continental slope—The continental margin 

province that lies between the continental 

shelf and continental rise, characterized by 

a steep slope (about 3°-6°).

Critical habitat—Specific areas essential to the 

conservation of a protected species and that 

may require special management 

considerations or protection.

Crude oil—Petroleum in its natural state as it 

emerges from a well or after it passes 

through a gas-oil separator, but before 

refining or distillation. An oily, flammable, 

bituminous liquid that is essentially a 

complex mixture of hydrocarbons of 

different types with small amounts of other 

substances. 
Glossary 8-5 

Delineation well—A well that is drilled for the 

purpose of determining the size and/or 

volume of an oil or gas reservoir.

Demersal—Living at or near the bottom of the 

sea.

Development—Activities that take place 

following discovery of economically 

recoverable mineral resources, including 

geophysical surveying, drilling, platform 

construction, operation of onshore support 

facilities, and other activities that are for the 

purpose of ultimately producing the 

resources.

Development and Production Plan (DPP)—A 

document that must be prepared by the 

operator and submitted to BOEM for 

approval before any development and 

production activities are conducted on a 

lease or unit in any OCS area other than the 

western Gulf of Mexico.

Development Operations Coordination 

Document (DOCD)—A document that must 

be prepared by the operator and submitted 

to BOEM for approval before any 

development or production activities are 

conducted on a lease in the western Gulf of 

Mexico.

Development well—A well drilled to a known 

producing formation to extract oil or gas; a 

production well; distinguished from a wildcat 

or exploration well and from an offset well.

Direct employment—Consists of those 

workers involved in the primary industries of 

oil and gas exploration, development, and 

production operations (Standard Industrial 

Classification Code 13—Oil and Gas 

Extraction).

Discharge—Something that is emitted; flow 

rate of a fluid at a given instant expressed 

as volume per unit of time.

Dispersant—A suite of chemicals and solvents 

used to break up an oil slick into small 

droplets, which increases the surface area 

of the oil and hastens the processes of 

weathering and microbial degradation.

Dispersion—A suspension of finely divided 

particles in a medium.

Drilling mud—A mixture of clay, water or 

refined oil, and chemical additives pumped 

continuously downhole through the drill pipe 

and drill bit, and back up the annulus 

between the pipe and the walls of the 

borehole to a surface pit or tank. The mud 

lubricates and cools the drill bit, lubricates 

the drill pipe as it turns in the wellbore, 

carries rock cuttings to the surface, serves 

to keep the hole from crumbling or 

collapsing, and provides the weight or 

hydrostatic head to prevent extraneous 

fluids from entering the well bore and to 

downhole pressures; also called drilling 

fluid.

Economically recoverable resources—An 

assessment of hydrocarbon potential that 

takes into account the physical and 

technological constraints on production and 

the influence of costs of exploration and 

development and market price on industry 

investment in OCS exploration and 

production.

Effluent—The liquid waste of sewage and 

industrial processing.

Effluent limitations—Any restriction 

established by a State or the USEPA on 

quantities, rates, and concentrations of 

chemical, physical, biological, and other 

constituents discharged from point sources 
8-6 Gulf of Mexico Multisale EIS

into U.S. waters, including schedules of 

compliance.

Epifaunal—Animals living on the surface of 

hard substrate.

Essential habitat—Specific areas crucial to the 

conservation of a species and that may 

necessitate special considerations.

Estuary—Coastal semienclosed body of water 

that has a free connection with the open sea 

and where freshwater meets and mixes with 

seawater.

Eutrophication—Enrichment of nutrients in the 

water column by natural or artificial methods 

accompanied by an increase of respiration, 

which may create an oxygen deficiency.

Exclusive Economic Zone (EEZ)—The 

maritime region extending 200 nmi (230 mi; 

370 km) from the baseline of the territorial 

sea, in which the United States has 

exclusive rights and jurisdiction over living 

and nonliving natural resources.

Exploration Plan (EP)—A plan that must be 

prepared by the operator and submitted to 

BOEM for approval before any exploration 

or delineation drilling is conducted on a 

lease.

Exploration well—A well drilled in unproven or 

semi-proven territory to determining whether 

economic quantities of oil or natural gas 

deposit are present.

False crawls—Refers to when a female sea 

turtle crawls up on the beach to nest 

(perhaps) but does not and returns to the 

sea without laying eggs.

Field—An accumulation, pool, or group of pools 

of hydrocarbons in the subsurface. A 

hydrocarbon field consists of a reservoir in a 

shape that will trap hydrocarbons and that is 

covered by an impermeable, sealing rock.

Floating production, storage, and offloading 

(FPSO) system—A tank vessel used as a 

production and storage base; produced oil is 

stored in the hull and periodically offloaded 

to a shuttle tanker for transport to shore.

Gathering lines—A pipeline system used to 

bring oil or gas production from a number of 

separate wells or production facilities to a 

central trunk pipeline, storage facility, or 

processing terminal.

Geochemical—Of or relating to the science 

dealing with the chemical composition of 

and the actual or possible chemical changes 

in the crust of the earth.

Geophysical survey—A method of exploration 

in which geophysical properties and 

relationships are measured remotely by one 

or more geophysical methods.

Habitat—A specific type of environment that is 

occupied by an organism, a population, or a 

community.

Hermatypic coral—Reef-building corals that 

produce hard, calcium carbonate skeletons 

and that possess symbiotic, unicellular 

algae within their tissues.

Harassment—An intentional or negligent act or 

omission that creates the likelihood of injury 

to wildlife by annoying it to such an extent 

as to significantly disrupt normal behavior 

patterns that include, but are not limited to, 

feeding or sheltering.

Hermatypic—Corals in the order Scleractinia 

that build reefs by depositing hard

calcareous material for their skeletons,

forming the stony framework of the reef. 

Corals that do not contribute to coral reef
Glossary 8-7 

development are referred to as ahermatypic

(non-reef-building) species.

Hydrocarbons—Any of a large class of organic 

compounds containing primarily carbon and 

hydrogen. Hydrocarbon compounds are 

divided into two broad classes: aromatic 

and aliphatics. They occur primarily in 

petroleum, natural gas, coal, and bitumens.

Hypoxia—Depressed levels of dissolved 

oxygen in water, usually resulting in 

decreased metabolism.

Incidental take—Takings that result from, but 

are not the purpose of, carrying out an 

otherwise lawful activity (e.g., fishing) 

conducted by a Federal agency or applicant 

(refer to Taking).

Indirect employment—Secondary or 

supporting oil- and gas-related industries, 

such as the processing of crude oil and gas 

in refineries, natural gas plants, and 

petrochemical plants.

Induced employment—Tertiary industries that 

are created or supported by the 

expenditures of employees in the primary or 

secondary industries (direct and indirect 

employment), including consumer goods 

and services such as food, clothing, 

housing, and entertainment.

Infrastructure—The facilities associated with 

oil and gas development, e.g., refineries, 

gas processing plants, etc.

Jack-up rig—A barge-like, floating platform with 

legs at each corner that can be lowered to 

the sea bottom to raise the platform above 

the water.

Kick—A deviation or imbalance, typically 

sudden or unexpected, between the 

downward pressure exerted by the drilling 

fluid and the upward pressure of in-situ

formation fluids or gases.

Landfall—The site where a marine pipeline 

comes to shore.

Lease—Authorization that is issued under 

Section 8 or maintained under Section 6 of 

the Outer Continental Shelf Lands Act and 

that authorizes exploration for, and 

development and production of, minerals.

Lease sale—The competitive auction of leases 

granting companies or individuals the right 

to explore for and develop certain minerals 

under specified conditions and periods of 

time.

Lease term—The initial period for oil and gas 

leases, usually a period of 5, 8, or 10 years 

depending on water depth or potentially 

adverse conditions.

Lessee—A party authorized by a lease, or an 

approved assignment thereof, to explore for 

and develop and produce the leased 

deposits in accordance with regulations at 

30 CFR part 250 and 30 CFR part 550.

Littoral zone—Marine ecological realm that 

experiences the effects of tidal and 

longshore currents and breaking waves to a 

depth of 5-10 m (16-33 ft) below the low-tide 

level, depending on the intensity of storm 

waves.

Longshore sediment transport—The

cumulative movement of beach sediment 

along the shore (and nearshore) by waves

arriving at an angle to the coastline and by 

currents generated by such waves. 

Lower marine riser package—The head 

assembly of a subsurface well at the point 

where the riser connects to a blowout 

preventer. 
8-8 Gulf of Mexico Multisale EIS

Macondo—Prospect name given by BP to the 

Mississippi Canyon Block 252 exploration 

well that the Deepwater Horizon rig was 

drilling when a blowout occurred on April 20, 

2010.

Macondo spill—The name given to the oil spill 

that resulted from the explosion and sinking 

of the Deepwater Horizon rig from the 

period between April 24, 2010, when search 

and recovery vessels on site reported oil at 

the sea surface, and September 19, 2010, 

when the uncontrolled flow from the 

Macondo well was capped.

Marshes—Persistent, emergent, nonforested 

wetlands characterized by predominantly 

cordgrasses, rushes, and cattails.

Military warning area—An area established by 

the U.S. Department of Defense within 

which military activities take place.

Minerals—As used in this document, minerals 

include oil, gas, sulphur, and associated 

resources, and all other minerals authorized 

by an Act of Congress to be produced from 

public lands as defined in Section 103 of the 

Federal Land Policy and Management Act 

of 1976.

Naturally occurring radioactive materials 

(NORM)—naturally occurring material that 

emits low levels of radioactivity, originating 

from processes not associated with the 

recovery of radioactive material. The 

radionuclides of concern in NORM are 

Radium-226, Radium-228, and other 

isotopes in the radioactive decay chains of 

uranium and thorium.

Nepheloid—A layer of water near the bottom 

that contains significant amounts of 

suspended sediment.

Nonattainment area—An area that is shown by 

monitoring data or by air-quality modeling 

calculations to exceed primary or secondary 

ambient air quality standards established by 

USEPA.

Nonhazardous oil-field wastes (NOW)—

Wastes generated by exploration, 

development, or production of crude oil or 

natural gas that are exempt from hazardous 

waste regulation under the Resource 

Conservation and Recovery Act (Regulatory 

Determination for Oil and Gas and 

Geothermal Exploration, Development and 

Production Wastes, dated June 29, 1988, 

53 FR 25446; July 6, 1988). These wastes 

may contain hazardous substances.

Oceanic zone—Offshore water >200 m (656 ft) 

deep. It is the region of open sea beyond 

the edge of the continental shelf and 

includes 65 percent of the ocean's

completely open water.

Offloading—Unloading liquid cargo, crude oil, 

or refined petroleum products.

Operational discharge—Any incidental 

pumping, pouring, emitting, emptying, or 

dumping of wastes generated during routine 

offshore drilling and production activities.

Operator—An individual, partnership, firm, or 

corporation having control or management 

of operations on a leased area or portion 

thereof. The operator may be a lessee, 

designated agent of the lessee, or holder of 

operating rights under an approved 

operating agreement.

Organic matter—Material derived from living 

plants or animals.

Outer Continental Shelf (OCS)—All 

submerged lands that comprise the 
Glossary 8-9 

continental margin adjacent to the United 

States and seaward of State offshore lands.

Passerines—Perching birds (members of the 

Order Passeriformes) and songbirds.

Potential Biological Removal (PBR)—Of or 

pertaining to the open sea; associated with 

open water beyond the direct influence of 

coastal systems.

Pelagic—Of or pertaining to the open sea; 

associated with open water beyond the 

direct influence of coastal systems.

Plankton—Passively floating or weakly motile 

aquatic plants (phytoplankton) and animals 

(zooplankton).

Platform—A steel or concrete structure from 

which offshore development wells are 

drilled.

Play—A prospective subsurface area for 

hydrocarbon accumulation that is 

characterized by a particular structural style 

or depositional relationship.

Primary production—Organic material 

produced by photosynthetic or 

chemosynthetic organisms.

Produced water—Total water discharged from 

the oil and gas extraction process; 

production water or production brine.

Production—Activities that take place after the 

successful completion of any means for the 

extraction of resources, including bringing 

the resource to the surface, transferring the 

produced resource to shore, monitoring 

operations, and drilling additional wells or 

workovers.

Province—A spatial entity with common 

geologic attributes. A province may include 

a single dominant structural element such 

as a basin or a fold belt, or a number of 

contiguous related elements.

Ram—The main component of a blowout 

preventer designed to shear casing and 

tools in a wellbore or to seal an empty 

wellbore. A blind shear ram accomplishes 

the former and a blind ram the latter.

Recoverable reserves—The portion of the 

identified hydrocarbon or mineral resource 

that can be economically extracted under 

current technological constraints.

Recoverable resource estimate—An 

assessment of hydrocarbon or mineral 

resources that takes into account the fact 

that physical and technological constraints 

dictate that only a portion of resources can 

be brought to the surface. 

Recreational beaches—Frequently visited, 

sandy areas along the Gulf of Mexico 

shorefront that support multiple recreational 

activities at the land-water interface. 

Included are National Seashores, State 

Park and Recreational Areas, county and 

local parks, urban beachfronts, and private 

resorts.

Refining—Fractional distillation of petroleum, 

usually followed by other processing (e.g., 

cracking).

Relief—The difference in elevation between the 

high and low points of a surface.

Reserves—Proved oil or gas resources. 

Rig—A structure used for drilling an oil or gas 

well.

Riser insertion tube tool—A “straw” and 

gasket assembly improvised during the 

Macondo spill response that was designed 

to siphon oil and gas from the broken riser 

of the Deepwater Horizon rig lying on the 
8-10 Gulf of Mexico Multisale EIS

sea bottom (an early recovery strategy for 

the Macondo spill in May 2010).

Royalty—A share of the minerals produced 

from a lease paid in either money or “inkind” to the landowner by the lessee.

Saltwater intrusion—Saltwater invading a 

body of freshwater.

Sciaenids—Fishes belonging to the croaker 

family (Sciaenidae).

Seagrass beds—More or less continuous mats 

of submerged, rooted, marine, flowering 

vascular plants occurring in shallow tropical 

and temperate waters. Seagrass beds 

provide habitat, including breeding and 

feeding grounds, for adults and/or juveniles 

of many of the economically important 

shellfish and finfish.

Sediment—Material that has been transported 

and deposited by water, wind, glacier, 

precipitation, or gravity; a mass of deposited 

material.

Seeps (hydrocarbon)—Gas or oil that reaches 

the surface along bedding planes, fractures, 

unconformities, or fault planes.

Sensitive area—An area containing species, 

populations, communities, or assemblages 

of living resources, that is susceptible to 

damage from normal OCS oil- and gasrelated activities. Damage includes 

interference with established ecological 

relationships.

Shear ram—The component in a BOP that 

cuts, or shears, through the drill pipe and 

forms a seal against well pressure. Shear 

rams are used in floating offshore drilling 

operations to provide a quick method of 

moving the rig away from the hole when 

there is no time to trip the drill stem out of 

the hole.

Shoreline Cleanup and Assessment Team—

The on-the-scene responders for post-spill 

shoreline protection who established 

priorities, standardized procedures, and 

terminology.

Site fidelity or philopatry—The tendency to 

return to a previously occupied location.

Spill of National Significance—Designation by 

the USEPA Administrator under 40 CFR § 

300.323 for discharges occurring in the 

inland zone and the Commandant of the 

U.S. Coast Guard for discharges occurring 

in the coastal zone, authorizing the 

appointment of a National Incident 

Commander for spill-response activity.

State coastal zone boundary—The State 

coastal zone boundaries for each CZMAaffected State are defined at 

https://coast.noaa.gov/czm/media/StateCZB

oundaries.pdf. 

Structure—Any OCS facility that extends from 

the seafloor to above the waterline; in 

petroleum geology, any arrangement of 

rocks that may hold an accumulation of oil 

or gas.

Subarea—A discrete analysis area.

Subsea isolation device—An emergency 

disconnection and reconnection assembly 

for the riser at the seafloor.

Supply vessel—A boat that ferries food, water, 

fuel, and drilling supplies and equipment to 

an offshore rig or platform and returns to 

land with refuse that cannot be disposed of 

at sea.

Taking—To harass, harm, pursue, hunt, shoot, 

wound, kill, trap, capture, or collect any 

endangered or threatened species, or to 

attempt to engage in any such conduct 

(including actions that induce stress, 
Glossary 8-11

adversely impact critical habitat, or result in 

adverse secondary or cumulative impacts). 

Harassments are the most common form of 

taking associated with OCS Program 

activities.

Tension-leg platform (TLP)—A production 

structure that consists of a buoyant platform 

tethered to concrete pilings on the seafloor 

with flexible cable.

Tidal prism—The volume of water in an estuary 

or inlet between mean high tide and mean 

low tide, or the volume of water leaving an 

estuary at ebb tide.

Total dissolved solids—The total amount of 

solids that are dissolved in water.

Total suspended particulate matter—The 

total amount of suspended solids in water.

Total suspended solids—The total amount of 

suspended solids in water.

Trunkline—A large-diameter pipeline receiving 

oil or gas from many smaller tributary 

gathering lines that serve a large area; 

common-carrier line; main line.

Turbidity—Reduced water clarity due to the 

presence of suspended matter.

Volatile organic compound (VOC)—Any 

organic compound that is emitted to the 

atmosphere as a vapor.

Water test areas—Areas within the eastern 

Gulf where U.S. Department of Defense 

research, development, and testing of 

military planes, ships, and weaponry take 

place.

Weathering (of oil)—The aging of oil due to its 

exposure to the atmosphere, causing 

marked alterations in its physical and 

chemical makeup.

APPENDIX A 

POSTLEASE PERMITTING AND APPROVAL PROCESSES

Postlease Permitting and Approval Processes A-3 

A POSTLEASE PERMITTING AND APPROVAL PROCESSES 

BOEM is responsible for managing the development of the Nation’s offshore energy and 

mineral resources in an environmentally and economically responsible way. The functions of BOEM 

include leasing, exploration and development plan administration, geological and geophysical 

permitting, environmental studies, NEPA analysis, resource evaluation, economic analysis, marine 

minerals, and renewable energy development. BOEM’s regulations for oil, gas, and sulphur lease 

operations are specified in 30 CFR parts 556, 550, 551 (except those aspects that pertain to drilling), 

and 554.

The BSEE is responsible for enforcing safety and environmental regulations. The functions 

of BSEE include all field operations, including permitting and research, inspections, offshore 

regulatory programs, oil-spill response, and training and environmental compliance functions. The 

BSEE’s regulations for oil, gas, and sulphur operations are specified in 30 CFR parts 250 and 254.

Measures to minimize potential impacts are an integral part of the OCS Program. These 

measures are implemented through lease stipulations, operating regulations, NTLs, and projectspecific requirements or approval conditions that are applied to all plans for OCS oil- and gas-related 

activities (e.g., exploration and development plans, pipeline applications, and structure-removal 

applications). These measures address concerns such as endangered and threatened species, 

geologic and manmade hazards, military warning and ordnance disposal areas, archaeological sites, 

air quality, oil-spill response planning, chemosynthetic communities, artificial reefs, operations in 

hydrogen sulfide (H2S) prone areas, and shunting of drill effluents in the vicinity of biologically 

sensitive features. Refer to Appendix B (“Commonly Applied Mitigating Measures”) for more 

information on the mitigations that BOEM and BSEE could apply at the postlease stage. Standard 

mitigating measures in the Gulf of Mexico OCS include the following:

• limiting the size of explosive charges used for structure removals (NTL 

2010-G05);

• requiring placement of explosive charges at least 15 ft (5 m) below the mudline;

• requiring site-clearance procedures to eliminate potential snags to commercial 

fishing nets upon abandonment;

• establishment of No Activity and Modified Activity Zones around high-relief live 

bottoms;

• requiring remote-sensing surveys to detect and avoid potential archaeological 

sites and biologically sensitive areas such as low-relief live bottoms, pinnacles, 

and chemosynthetic communities; and

• requiring coordination with the military to prevent multiuse conflicts between OCS 

and military activities.
A-4 Gulf of Mexico Multisale EIS

BOEM and BSEE issue NTLs to provide clarification, description, or interpretation of a

regulation; guidelines on the implementation of a special lease stipulation or regional requirement; or 

convey administrative information. A detailed listing of current Gulf of Mexico OCS Region NTLs is 

available through BOEM’s and BSEE’s Gulf of Mexico OCS Region websites (http://www.boem.gov/

notices-to-lessees-and-operators/ and http://www.bsee.gov/Regulations-and-Guidance/Notices-toLessees-and-Operators/) or through the Region’s Public Information Office at 1-800-200-GULF.

Formal plans must be submitted to BOEM for review and approval before any projectspecific activities, except for ancillary activities (such as geological and geophysical activities or 

studies that model potential oil and hazardous substance spills), can begin on a lease. Conditions of 

approval are mechanisms to control or mitigate potential safety or environmental problems 

associated with proposed operations. Conditions of approval are based on BOEM’s technical and 

environmental evaluations of the proposed operations. Comments from Federal and State agencies 

(as applicable) are also considered in establishing conditions. Conditions may be applied to any 

OCS plan, permit, right-of-use of easement, or pipeline right-of-way grant.

Some BOEM-identified mitigating measures are implemented through cooperative 

agreements or coordination with the oil and gas industry and Federal and State agencies. These 

measures include NMFS’s Observer Program to protect marine mammals and sea turtles when OCS 

structures are removed using explosives, labeling of operational supplies to track sources of 

accidental debris loss, development of methods of pipeline landfall to eliminate impacts to barrier 

beaches, and semiannual beach cleanup events.

The following postlease approval processes apply to the proposed lease sale areas in the 

WPA, CPA, and EPA.

A.1 GEOLOGICAL AND GEOPHYSICAL SURVEY AUTHORIZATIONS

A geological and geophysical (G&G) permit must be obtained from BOEM prior to conducting 

off-lease geological or geophysical exploration or scientific research on unleased OCS lands or on 

lands under lease to a third party (30 CFR §§ 551.4(a) and (b)). Geological investigations include 

various seafloor sampling techniques to determine the geochemical, geotechnical, or engineering 

properties of the sediments.

Ancillary activities, or G&G exploration and development activities conducted on lease, are 

defined in 30 CFR § 250.105 and 30 CFR § 550.105 with regulations outlined in 30 CFR §§ 550.207 

through 550.210. Ancillary activities include geological and high-resolution geophysical, 

geotechnical, archaeological, biological, physical oceanographic, meteorological, socioeconomic, or 

other surveys; or various types of modeling studies. This Agency issued NTL 2009-G34, “Ancillary 

Activities,” to provide guidance and clarification on conducting ancillary activities in BOEM’s Gulf of 

Mexico OCS Region. Operators should notify the Gulf of Mexico OCS Region, Regional Supervisor, 

Office of Leasing and Plans, Plans Section, in writing 30 days in advance before conducting any of 

the following types of ancillary activities related to a G&G exploration or development G&G activity:
Postlease Permitting and Approval Processes A-5 

• involving the use of an airgun or airgun array anywhere in the GOM regardless of 

water depth;

• independent of water depth, involving the use of explosives as an energy source; 

and

• independent of water depth, including ocean-bottom cable surveys, node 

surveys, and time-lapse (4D) surveys.

Additionally, NTL 2009-G34 clarifies that the Gulf of Mexico OCS Region, Regional 

Supervisor, Office of Leasing and Plans, Plans Section, should be notified in writing 15 days in 

advance before conducting the following types of other ancillary activities:

• involving the use of an airgun or airgun array anywhere in the EPA of the GOM 

regardless of water depth and 200 m (656 ft) or greater for the rest of the GOM;

• involving bottom disturbance, independent of water depth, including oceanbottom cable surveys, node surveys, and time-lapse (4D) surveys; and

• a geotechnical evaluation involving piston/gravity coring or the recovery of 

sediment specimens by grab sampling or similar technique and/or any dredging 

or other ancillary activity that disturbs the seafloor (including deployment and 

retrieval of bottom cables, anchors, or other equipment).

This NTL also provides guidance for each type of ancillary activity, the type and level of 

BOEM review, and follow-up, post-survey report requirements.

Shallow hazard assessments are required under 30 CFR §§ 550.214 and 50.244; NTL 

2008-G05, “Shallow Hazards Program,” explains the requirements for these surveys and their 

reports. Included in shallow hazard assessments is a structural and stratigraphic interpretation of 

seismic data to qualitatively delineate abnormal pressure zones, shallow free gas, seafloor 

instability, shallow waterflow, and gas hydrates.

Seismic surveys are performed to obtain information on surface and near-surface geology 

and on subsurface geologic formations. Low-energy, high-resolution seismic surveys collect data on 

surficial geology used to identify potential shallow geologic or manmade hazards (e.g., faults or 

pipelines) for engineering and site planning for bottom-founded structures. The high-resolution 

surveys are also used to identify environmental and archaeological resources such as low-relief live 

bottom areas, pinnacles, chemosynthetic community habitat, and shipwrecks. High-energy, deeppenetration, common-depth-point (CDP) seismic surveys obtain data about geologic formations 

thousands of feet below the seafloor. The two-dimensional (2D) and three-dimensional (3D) CDP 

data are used to map structure features of stratigraphically important horizons in order to identify 

potential hydrocarbon traps. They can also be used to map the extent of potential habitat for 

chemosynthetic communities. In some situations, a set of 3D surveys can be run over a time 
A-6 Gulf of Mexico Multisale EIS

interval to produce a four-dimensional (4D), or “time-lapse,” survey that could be used to 

characterize production reservoirs.

BOEM’s predecessor completed the Geological and Geophysical Exploration for Mineral 

Resources on the Gulf of Mexico Outer Continental Shelf: Programmatic Environmental 

Assessment (G&G Programmatic EA) (USDOI, MMS, 2004). Upon receiving a complete G&G 

permit application, BOEM conducts a NEPA review that will result in a categorical exclusion, an EA, 

or an EIS in accordance with the G&G Programmatic EA’s conclusions, NEPA guidelines, and other 

applicable BOEM policies. When required under an approved coastal management program, 

proposed G&G permit activities must receive State concurrence prior to BOEM permit approval.

A.2 EXPLORATION AND DEVELOPMENT PLANS

To ensure compliance with the OCSLA, other laws, applicable regulations, and lease 

provisions, and to enable BOEM to carry out its functions and responsibilities, formal plans (30 CFR 

§§ 550.211 and 550.241) with supporting information must be submitted for review and approval by 

BOEM before an operator may begin exploration, development, or production activities on any lease. 

Supporting environmental information, archaeological reports, biological reports (monitoring and/or 

live-bottom survey), and other environmental data determined necessary must be submitted with an 

OCS plan. This information provides the basis for an analysis of both offshore and onshore impacts 

that may occur as a result of the activities. BOEM may require additional specific supporting 

information to aid in the evaluation of the potential environmental impacts of the proposed activities. 

BOEM can require an amendment of an OCS plan based on inadequate or inaccurate supporting 

information. The 30 CFR part 550 subpart B regulations were revised to update the information that 

must be submitted with OCS plans and were published in the Federal Register on August 30, 2005 

(Federal Register, 2005).

The OCS plans are reviewed by subject-matter experts that include, but are not limited to 

geologists, geophysicists, engineers, biologists, archaeologists, air quality specialists, water quality 

specialists, oil-spill specialists, NEPA coordinators, and/or environmental scientists. The plans and 

accompanying information are evaluated to determine whether any seafloor or drilling hazards are 

present; that air and water quality issues are addressed; that plans for hydrocarbon resource 

conservation, development, and drainage are adequate; that environmental issues and potential 

impacts are properly evaluated and mitigated; and that a proposed action is in compliance with 

NEPA, the Coastal Zone Management Act, BOEM’s operating regulations, and other requirements. 

Federal agencies, including the FWS, NMFS, USEPA, U.S. Navy, U.S. Air Force, and USCG, may 

be consulted if the proposal has the potential to impact areas under their jurisdiction. Each Gulf 

Coast State has a designated CZM agency that takes part in the review process. The OCS plans 

are also made available to the general public for comment through BOEM’s Gulf of Mexico OCS 

Region’s Public Information Office.

In response to deepwater activities in the Gulf of Mexico, this Agency developed a 

comprehensive strategy to address NEPA compliance and environmental issues in the deepwater 
Postlease Permitting and Approval Processes A-7 

areas. A key component of that strategy was the completion of a Programmatic EA to evaluate the 

potential effects of deepwater technologies and operations (USDOI, MMS, 2000). As a supplement 

to the Programmatic EA, this Agency prepared a series of technical papers that provide a summary 

description of the different types of structures that may be employed in the development and 

production of hydrocarbon resources in the deepwater areas of the GOM (Regg et al., 2000). 

Information in the Programmatic EA and technical papers were used in the preparation of this 

Multisale EIS.

On the basis of BOEM’s reviews of the OCS plan, the findings of the proposal-specific 

environmental review, EA, or EIS, and other applicable BOEM studies and NEPA documents, the 

OCS plan is approved or disapproved by BOEM, or modified and resubmitted for further analyses 

and decision. Although few OCS plans are ultimately disapproved, many must be amended prior to 

approval to fully comply with BOEM’s operating regulations and requirements or other Federal laws, 

to address reviewing agencies’ concerns, or to avoid potential hazards or impacts to environmental 

resources.

Exploration Plans

An exploration plan (EP) must be submitted to BOEM for review and approval before any 

exploration activities, except for preliminary activities (such as hazard surveys or geophysical 

surveys), can begin on a lease. The EP describes exploration activities, drilling rig or vessel, 

proposed drilling and well-testing operations, environmental monitoring plans, and other relevant 

information, and it includes a proposed schedule of the exploration activities. Guidelines and 

environmental information requirements for lessees and operators submitting an EP are addressed 

in 30 CFR § 550.211 and are further explained in NTL 2008-G05, “Shallow Hazards Program,” and 

NTL 2009-G27, “Submitting Exploration Plans and Development Operations Coordination 

Documents.” The NTL 2008-G04 provides guidance on information requirements and establishes 

the contents for OCS plans required by 30 CFR part 550 subpart B. The NTL 2015-BOEM-N01, 

“Information Requirements for Exploration Plans, Development and Production Plans, and 

Development Operations Coordination Documents on the OCS for Worst Case Discharge and 

Blowout Scenarios,” effective January 14, 2015, supersedes NTL 2010-N06. The NTL 2009-G27 

clarifies guidance for submitting OCS plans to BOEM’s Gulf of Mexico OCS Region.

After receiving an EP, BOEM determines if the plan is complete and adequate before 

technical and environmental reviews. BOEM evaluates the proposed exploration activities for 

potential impacts relative to geohazards and manmade hazards (including existing pipelines), 

archaeological resources, endangered species, sensitive biological features, water and air quality, 

oil-spill response, State CZMA requirements, and other uses (e.g., military operations) of the OCS. 

The EP is reviewed for compliance with all applicable laws and regulations.

A site-specific environmental review (SSER) is generated and completed for each plan. As a 

result of the SSER, a determination is made whether a categorical exclusion can be applied or 

whether additional NEPA analysis in the form of an EA or EIS will be prepared for the proposed 
A-8 Gulf of Mexico Multisale EIS

activity. Categorical exclusions are "a category of actions which do not individually or cumulatively 

have a significant effect on the human environment and for which, therefore, neither an 

environmental assessment nor an environmental impact statement is required" (40 CFR § 1508.4). 

In the event an action cannot be categorically excluded, the decision to prepare an EA will be made 

by the Regional Supervisor, Leasing and Environment or the Chief, Environmental Division. The 

SSER is based on the best available information, which may include the geophysical report (for 

determining the potential for the presence of deepwater benthic communities); archaeological report; 

air emissions data; waste and discharge data; live-bottom survey and report; biological monitoring 

plan; and recommendations by the affected State(s), DOD, FWS, NMFS, and/or internal BOEM 

offices. As part of the review process, each EP must contain a certification of consistency and the 

necessary data and information for the State to determine that the proposed activities comply with 

the enforceable policies of the States’ approved Coastal Management Plan (CMP) and that such 

activities will be conducted in a manner that is consistent with the CMP (16 U.S.C. § 1456(c)(3)(A) 

and 15 CFR § 930.76).

If the EP is approved, and prior to conducting drilling operations, the operator is required to 

submit and obtain approval for an Application for Permit to Drill (APD) (refer to Wells under Permits 

and Applications below).

Operations Plans

In 1992, this Agency formed an internal Deepwater Task Force to address technical issues 

and regulatory concerns relating to deepwater (>1,000 ft; 305 m) operations and projects utilizing 

subsea technology. Based on the Deepwater Task Force’s recommendation, an NTL (2000-N06) 

was at first developed that was incorporated into 30 CFR part 550 subpart B. The revisions to 

subpart B were finalized August 30, 2005, and it requires operators to submit a Deepwater 

Operations Plan (DWOP) for all operations in deep water (400 m [1,312 ft] or greater) and all 

projects using subsea technology. DeepStar, an industry-wide cooperative workgroup focused on 

deepwater regulatory issues and critical technology development issues, worked closely with this 

Agency’s Deepwater Task Force to develop the initial guidelines for the DWOP. The DWOP 

requirement was established to address regulatory issues and concerns that were not addressed in 

the Agency’s then-existing regulatory framework, and it is intended to initiate an early dialogue 

between BSEE and industry before major capital expenditures on deepwater and subsea projects 

are committed. Deepwater technology has been evolving faster than BSEE’s ability to revise OCS 

regulations; the DWOP was established through the NTL process, which provides for a more timely 

and flexible approach to provide guidance on regulatory requirements and keep pace with the 

expanding deepwater operations and subsea technology.

The DWOP is intended to address the different functional requirements of production 

equipment in deep water, particularly the technological requirements associated with subsea 

production systems, and the complexity of deepwater production facilities. The DWOP provides 

BSEE with information specific to deepwater equipment issues to demonstrate that a deepwater 

project is being developed in an acceptable manner as mandated in the OCSLA, as amended, and 
Postlease Permitting and Approval Processes A-9 

BSEE’s operating regulations at 30 CFR part 250. The BSEE reviews deepwater development 

activities from a total system perspective, emphasizing operational safety, environmental protection, 

and conservation of natural resources. The DWOP process is a phased approach that parallels the 

operator’s state of knowledge about how a field will be developed. A DWOP outlines the design, 

fabrication, and installation of the proposed development/production system and its components. A 

DWOP will include structural aspects of the facility (i.e., fixed, floating, or subsea); station-keeping 

(includes mooring system); wellbore, completion, and riser systems; safety systems; product 

removal or offtake systems; and hazards and operability of the production system. The DWOP 

provides BSEE with the information to determine that the operator has designed and built sufficient 

safeguards into the production system to prevent the occurrence of significant safety or 

environmental incidents. The DWOP, in conjunction with other permit applications, provides BSEE 

the opportunity to assure that the production system is suitable for the conditions in which it will 

operate.

This Agency recently completed a review of several industry-developed, recommended 

practices that address the mooring and risers for floating production facilities. The recommended 

practices address such things as riser design, mooring system design (station-keeping), and hazard 

analysis. Hazard analyses allow BSEE to be assured that the operator has anticipated emergencies 

and is prepared to address them, either through their design or through the operation of the 

equipment in question. The BSEE released these clarifications of its requirements in recent NTL’s: 

NTL 2009-G03, “Synthetic Mooring Systems”; NTL 2009-G11, “Accidental Disconnect of Marine 

Drilling Risers”; and NTL 2009-G13, “Guidelines for Tie-downs on OCS Production Platforms for 

Upcoming Hurricane Seasons.”

Conservation Reviews

One of BOEM and BSEE’s primary responsibilities is to ensure development of economically 

producible reservoirs according to sound resource conservation, engineering, and economic 

practices as cited in 30 CFR §§ 550.202(c), 550.203, 550.210, 550.296, 550.297, 550.298, 550.299, 

250.204, and 250.205. Operators should submit the necessary information as part of their EP, initial 

and supplemental development operations and coordination documents (DOCDs) or development 

and production plans (DPPs), and Conservation Information Document. Conservation reviews are 

performed to ensure that economic reserves are fully developed and produced, and that there is no 

harm to the ultimate recovery.

Development Operations and Coordination Documents and Development and Production 

Plans

Before any development operations can begin on a lease in a proposed lease sale area, a 

DOCD/DPP must be submitted to BOEM for review and decision. A DOCD/DPP describes the 

proposed development activities, drilling activities, platforms or other facilities, proposed production 

operations, environmental monitoring plans, and other relevant information; and it includes a 

proposed schedule of development and production activities. Requirements for lessees and 
A-10 Gulf of Mexico Multisale EIS

operators submitting a DOCD/DPP are addressed in 30 CFR §§ 550.241 and 550.242, and 

information guidelines for DOCDs/DPPs are provided in NTLs 2008-G04, 2009-G27, and 2010-N06.

After receiving a DOCD/DPP, BOEM performs technical and environmental reviews. BOEM 

evaluates the proposed activity for potential impacts relative to geohazards and manmade hazards 

(including existing pipelines), archaeological resources, endangered species, sensitive biological 

features, water and air quality, oil-spill response, State CMPs requirements, and other uses (e.g., 

military operations) of the OCS. The DOCD/DPP is reviewed for compliance with all applicable laws 

and regulations.

A SSER is generated and completed for each DOCD/DPP. As a result of the SSER, a 

determination is made whether a categorical exclusion can be applied or whether additional NEPA 

analysis in the form of an EA or EIS will be prepared for the proposed activity. The environmental 

review is based on the best available information, which may include the geophysical report (for 

determining the potential for the presence of deepwater benthic communities); archaeological report; 

air emissions data; waste and discharge data, live-bottom survey and report; biological monitoring 

plan; and recommendations by the affected State(s), DOD, FWS, NMFS, and/or internal BOEM 

offices. 

As part of the review process, each DOCD/DPP must contain a certification of consistency 

and the necessary data and information for the State to determine that the proposed activities 

comply with the enforceable policies of the States’ approved CMP and that such activities will be 

conducted in a manner that is consistent with the CMP (16 U.S.C. § 1456(c)(3)(A) and 15 CFR § 

930.76).

New or Unusual Technologies

Technologies continue to evolve to meet the technical, environmental, and economic 

challenges of deepwater development. New or unusual technologies (NUTs) may be identified by 

the operator in its EP, DWOP, and DOCD/DPP or through BOEM’s plan review processes. Some of 

the technologies proposed for use by the operators are actually extended applications of existing 

technologies and interface with the environment in essentially the same way as well-known or 

conventional technologies. These technologies are reviewed by BOEM for alternative compliance or 

departures that may trigger additional environmental review. Some examples of new technologies 

that do not affect the environment differently and that are being deployed in the OCS Program are 

synthetic mooring lines, subsurface safety devices, and multiplex subsea controls.

Some new technologies differ from established technologies in how they function or interface 

with the environment. These include equipment or procedures that have not been installed or used 

in Gulf of Mexico OCS waters. Having no operational history, they have not been assessed by 

BOEM through technical and environmental reviews. New technologies may be outside the 

framework established by BOEM’s regulations and, thus, their performance (safety, environmental 

protection, efficiency, etc.) has not been addressed by BOEM. The degree to which these new 
Postlease Permitting and Approval Processes A-11

technologies interface with the environment and the potential impacts that may result are considered 

in determining the level of NEPA review that would be initiated.

BOEM has developed a NUTs’ matrix to help facilitate decisions on the appropriate level of 

engineering and environmental review needed for a proposed technology. Technologies will be 

added to the NUTs’ matrix as they emerge, and technologies will be removed from the matrix as 

sufficient experience is gained in their implementation. From an environmental perspective, the 

matrix characterizes new technologies into three categories: technologies that may affect the 

environment; technologies that do not interact with the environment any differently than 

“conventional” technologies; and technologies about which BOEM does not have sufficient 

information to determine their potential impacts to the environment. In this latter case, BOEM will 

seek to gain the necessary information from operators or manufacturers regarding the technologies 

to make an appropriate determination on potential effects on the environment.

Alternative Compliance and Departures

The BSEE’s project-specific engineering safety review ensures that equipment proposed for 

use is designed to withstand the operational and environmental conditions in which it would operate. 

When an OCS operator proposes the use of new or unusual technology or procedures not 

specifically addressed in established BSEE regulations, the operations are evaluated for alternative 

compliance or departure determination. Any new technologies or equipment that represents an 

alternative compliance or departure from existing BSEE regulations must be fully described and 

justified before they would be approved for use. For BSEE and BOEM to grant alternative 

compliance or departure approval, the operator must demonstrate an equivalent or improved degree 

of protection as specified in 30 CFR § 250.141 and 30 CFR § 550.141. Comparative analysis with 

other approved systems, equipment, and procedures is one tool that BSEE uses to assess the 

adequacy of protection provided by alternative technology or operations. Actual operational 

experience is necessary with alternative compliance measures before BSEE would consider them as 

proven technology.

Emergency Plans

Criteria, models, and procedures for shutdown operations and the orderly evacuation of 

platforms and rigs for an impending hurricane have been in place in the Gulf of Mexico OCS for 

more than 30 years. (Such emergency plans are different from the oil-spill response plans described 

later in this chapter.) Operating experience from extensive drilling activities and more than 

4,000 platforms during the 50-plus years of the Gulf of Mexico OCS Program have demonstrated the 

effectiveness and safety of securing wells and evacuating a facility in advance of severe weather 

conditions. Preinstallation efforts, historical experience with similar systems, testing, and the actual 

operating experience (under normal conditions and in response to emergency situations) are used to 

formulate the exact time needed to secure the wells and production facility and to evacuate it as 

necessary. Operators develop site-specific curtailment, securing, and evacuation plans that vary in 

complexity and formality by operator and type of activity. In general terms, all plans are intended to 

make sure the facility (or well) is secured in advance of an impending storm or developing 
A-12 Gulf of Mexico Multisale EIS

emergency. The operating procedures developed during the engineering, design, and 

manufacturing phases of the project, coupled with the results (recommended actions) from hazard 

analyses performed, are used to develop the emergency action and curtailment plans. Evacuation 

and production curtailment must consider a combination of factors, including the well status (drilling, 

producing, etc.) and the type and mechanics of wellbore operations. These factors are analyzed 

onsite through a decisionmaking process that involves onsite facility managers. The emphasis is on 

making real-time, situation-specific decisions and forecasting based on available information. 

Details of the shut-in criteria and various alerts are addressed on a case-by-case basis, as explained 

below.

Plans for shutting in production from the subsea wells are addressed as part of the 

emergency curtailment plan. The plan specifies the various alerts and shutdown criteria linked to 

both weather and facility performance data, with the intent to have operations suspended and the 

wells secured in the event of a hurricane or emergency situation. Ensuring adequate time to safely 

and efficiently suspend operations and secure the well is a key component of the planning effort. 

Clearly defined responsibilities for the facility personnel are part of the successful implementation of 

the emergency response effort.

For a severe weather event such as a hurricane, emergency curtailment plans would 

address the criteria and structured procedures for suspending operations and ultimately securing the 

wellbore(s) prior to weather conditions that could exceed the design operating limitations of the 

drilling or production unit. For drilling operations, the plan might also address procedures for 

disconnecting and moving the drilling unit off location after the well has been secured, should the 

environmental conditions exceed the floating drilling unit’s capability to maintain station. Curtailment 

of operations consists of various stages of “alerts” indicating the deterioration of meteorological, 

oceanographic, or wellbore conditions. Higher alert levels require increased monitoring, the 

curtailment of lengthy wellbore operations, and, if conditions warrant, the eventual securing of the 

well. If conditions improve, operations could resume based on the limitations established in the 

contingency plan for the known environmental conditions. The same emergency curtailment plans 

would be implemented in an anticipated or impending emergency situation, such as the threat of a 

terrorist attack.

Neither BSEE nor the USCG mandates that an operator must evacuate a production facility 

for a hurricane; it is a decision that rests solely with the operator. The USCG does require the 

submittal of an emergency evacuation plan that addresses the operator’s intentions for evacuation of 

nonessential personnel, egress routes on the production facility, lifesaving and personnel safety 

devices, firefighting equipment, etc. As activities move farther from shore, it may become safer to 

not evacuate the facility because helicopter operations become inherently more risky with greater 

flight times. Severe weather conditions also increase the risks associated with helicopter operations. 

The precedent for leaving a facility manned during severe weather is established in the North Sea 

and other operating basins.
Postlease Permitting and Approval Processes A-13

Redundant, fail-safe, automatic shut-in systems located inside the wellbore and at the sea 

surface, and in some instances at the seafloor, are designed to prevent or minimize pollution. These 

systems are designed and tested to ensure proper operation should a production facility or well be 

catastrophically damaged. Testing occurs at regular intervals with predetermined performance limits 

designed to ensure functioning of the systems in case of an emergency.

After the Deepwater Horizon explosion, oil spill, and cleanup, the testing requirements for 

well control systems came under immediate scrutiny in the DOI Secretary’s Increased Safety 

Measures for Energy Development on the Outer Continental Shelf (Safety Measures Report), which 

was delivered on May 27, 2010 (USDOI, 2010). The Safety Measures Report included a 

recommendation of a program for immediate recertification of blowout preventers (BOPs). As stated 

above, the new regulatory section at 30 CFR § 250.451(i) requires that, if a blind-shear ram or 

casing shear ram is activated in a well control situation where the pipe is sheared, the BOP stack 

must be retrieved, fully inspected, and tested.

A.3 PERMITS AND APPLICATIONS

After the approval of an EP or DOCD/DPP, the operator submits applications for specific 

activities to BOEM for approval. These applications include those for drilling wells; well-test flaring; 

temporary well abandonment; installing a well protection structure, production platforms, satellite 

structures, subsea wellheads and manifolds, and pipelines; installation of production facilities; 

commencing production operations; platform removal and lease abandonment; and pipeline 

decommissioning.

Wells

The BSEE requirements for the drilling of wells can be found at 30 CFR part 250 subpart D. 

Lessees are required to take precautions to keep all wells under control at all times. The lessee 

must use the best available and safest technology to enhance the evaluation of abnormal pressure 

conditions and to minimize the potential for uncontrolled well flow.

Prior to conducting drilling operations, the operator is required to submit and obtain approval 

for an Application for Permit to Drill (APD). The APD requires detailed information (including project 

layout at a scale of 1:24,000, design criteria for well control and casing, specifications for blowout 

preventers, a mud program, cementing program, directional drilling plans, etc.) to allow for BOEM’s 

evaluation of operational safety and pollution-prevention measures. The APD is reviewed for 

conformance with the engineering requirements and other technical considerations.

The BSEE is responsible for conducting technical and safety reviews of all drilling, workover, 

and production operations on the OCS. These detailed analyses determine if the lessee’s proposed 

operation is in compliance with all regulations and all current health, safety, environmental, and 

classical engineering standards.
A-14 Gulf of Mexico Multisale EIS

The BSEE regulations at 30 CFR §§ 250.1710-1717 address the requirements for 

permanent abandonment of a well on the OCS. A permanent abandonment includes the isolation of 

zones in the open wellbore, plugging of perforated intervals, plugging the annular space between 

casings (if they are open), setting a surface plug, and cutting and retrieving the casing at least 15 ft 

(5 m) below the mudline. All plugs must be tested in accordance with the regulations. There are no 

routine surveys of permanently abandoned well locations. If a well were found to be leaking, BOEM 

would require the operator of record to perform an intervention to repair the abandonment. If a well 

is temporarily abandoned at the seafloor, an operator must provide BSEE with an annual report 

summarizing plans to permanently abandon the well or to bring the well into production.

Platforms and Structures

The BSEE does a technical review of all proposed structure designs and installation 

procedures. All proposed facilities are reviewed for structural integrity. These detailed engineering 

reviews entail an evaluation of all operator proposals for fabrication, installation, modification, and 

repair of all mobile and fixed structures. The lessee must design, fabricate, install, use, inspect, and 

maintain all platforms and structures on the OCS to assure their structural integrity for the safe 

conduct of operations at specific locations. Applications for platform and structure approval are filed 

in accordance with 30 CFR § 250.901. Design requirements are presented in detail at 30 CFR §§ 

250.904 through 250.909. The lessee evaluates characteristic environmental conditions associated 

with operational functions to be performed. Factors such as waves, wind, currents, tides, 

temperature, and the potential for marine growth on the structure are considered. In addition, 

pursuant to 30 CFR §§ 250.902 and 250.903, a program has been established by BSEE to assure 

that new structures meeting the conditions listed under 30 CFR § 250.900(c) are designed, 

fabricated, and installed using standardized procedures to prevent structural failures. This program 

facilitates review of such structures and uses third-party expertise and technical input in the 

verification process through the use of a Certified Verification Agent. After installation, platforms and 

structures are required to be periodically inspected and maintained under 30 CFR § 250.912.

Pipelines

Regulatory processes and jurisdictional authority concerning pipelines on the OCS and in 

coastal areas are shared by several Federal agencies, including DOI, the Department of 

Transportation (DOT), the COE, the Federal Energy Regulatory Commission, and the USCG. Aside 

from the enforcement of pipeline regulations, these agencies have the responsibility of overseeing 

and regulating the following areas: the placement of structures on the OCS and pipelines in areas 

that affect navigation; the certification of proposed projects involving the transportation or sale of 

interstate natural gas, including OCS gas; and the right of eminent domain exercised by pipeline 

companies onshore. In addition, the DOT is responsible for promulgating and enforcing safety 

regulations for the transportation in interstate commerce of natural gas, liquefied natural gas, and 

hazardous liquids by pipeline. This includes, for the most part, offshore pipelines on State lands 

beneath navigable waters and on the OCS that are operated by transmission companies. The 

regulations are contained in 49 CFR parts 191 through 193 and 195. In a Memorandum of 

Understanding between the DOT and DOI dated December 10, 1996, each party’s respective 
Postlease Permitting and Approval Processes A-15

regulatory responsibilities are outlined. The DOT is responsible for establishing and enforcing 

design, construction, operation, and maintenance regulations, and for investigating accidents for all 

OCS transportation pipelines beginning downstream of the point at which operating responsibility 

transfers from a producing operator to a transporting operator. The DOI’s responsibility extends 

upstream from the transfer point described above.

The BSEE is responsible for regulatory oversight of the design, installation, modification, 

repair, and decommissioning of OCS producer-operated oil and gas pipelines. The BSEE’s 

operating regulations for pipelines, found at 30 CFR part 250 subpart J, are intended to provide safe 

and pollution-free transportation of fluids in a manner that does not unduly interfere with other users 

of the OCS. Pipeline applications may be for on-lease pipelines or right-of-way pipelines that cross 

other lessees’ leases or unleased areas of the OCS. Pipeline permit applications to BSEE include 

the pipeline location drawing, profile drawing, safety schematic drawing, pipe design data, a shallow 

hazard survey report, and an archaeological report, if applicable.

The BSEE evaluates the design and proposed route of all OCS pipelines. Proposed pipeline 

routes are evaluated for potential seafloor or subsea geologic hazards and other natural or 

manmade seafloor or subsurface features or conditions (including other pipelines) that could have 

an adverse impact on the pipeline or that could be adversely impacted by the proposed operations. 

Routes are also evaluated for potential impacts on archaeological resources and biological 

communities. A NEPA review is conducted in accordance with applicable policies and guidelines. 

BOEM prepares an EA on all pipeline right-of-ways that go ashore. For Federal consistency, 

applicants must comply with the regulations as clarified in NTL 2007-G20, “Coastal Zone 

Management Program Requirements for OCS Right-of-way Pipeline Applications.” All Gulf Coast 

States require consistency review of right-of-way pipeline applications as described in the clarifying 

NTL. The design of the proposed pipeline is evaluated for an appropriate cathodic protection system 

to protect the pipeline from the effects of external corrosion on the pipe; an external pipeline coating 

system to prolong the service life of the pipeline; measures to protect the inside of the pipeline from 

the detrimental effects, if any, of the fluids being transported; proposed maximum allowable 

operating pressure and hydrostatic test pressure of the line; inclusion and settings of all safety 

devices required by regulation; and protection of other pipelines crossing the proposed route. Such 

an evaluation includes the following: (1) reviewing the calculations used by the applicant in order to 

determine whether the applicant properly considered such elements as the grade of pipe to be used, 

the wall thickness of the pipe, de-rating factors (the practice of operating a component well inside its 

normal operating limits to reduce the rate at which the component deteriorates) related to the 

submerged and riser portions of the pipeline, the pressure rating of any valves or flanges to be 

installed in the pipeline, the pressure rating of any other pipeline(s) into which the proposed line 

might be tied, and the required pressure to which the line must be tested before it is placed in 

service; (2) protective safety devices such as pressure sensors and remotely operated valves, the 

physical arrangement of those devices proposed to be installed by the applicant for the purposes of 

protecting the pipeline from possible overpressure conditions and for detecting and initiating a 

response to abnormally low-pressure conditions; and (3) the applicant’s planned compliance with 

regulations requiring that pipelines installed in water depths less than 200 ft (61 m) be buried to a 
A-16 Gulf of Mexico Multisale EIS

depth of at least 3 ft (1 m) (30 CFR § 250.1003). In addition, pipelines crossing fairways require a 

COE permit and may be required to be buried greater than 3 ft (1 m).

Operators are required to periodically inspect pipeline routes. Monthly overflights are 

conducted to inspect pipeline routes for leakage. When a pipeline requires a repair, a repair plan 

notification and repair completion report must be submitted to BSEE for review and acceptance.

Applications for pipeline decommissioning must also be submitted for BSEE review and 

approval. Decommissioning applications are evaluated to ensure they will render the pipeline inert 

and/or to minimize the potential for the pipeline becoming a source of pollution by flushing and 

plugging the ends and to minimize the likelihood that the decommissioned line will become an 

obstruction to other users of the OCS by filling it with water and burying the ends.

In addition, BOEM’s Marine Minerals Program and Coastal Zone Management Coordinators, 

BSEE’s Pipelines Section, and the State of Louisiana’s Office of Coastal Management and Coastal 

Protection and Restoration Authority are working closely to ensure that sediment resources on the 

OCS are made available for restoration projects by requiring the removal of decommissioned 

pipelines. BOEM is also coordinating with BSEE’s Pipeline Section, the State of Louisiana, and 

applicants with regards to rerouting the proposed pipelines when an application is submitted for 

emplacement to avoid the sediment resources if at all possible.

A.4 INSPECTION AND ENFORCEMENT

The OCSLA authorizes and requires BSEE to provide for both an annual scheduled 

inspection and a periodic unscheduled (unannounced) inspection of all oil and gas operations on the 

OCS. The inspections are to assure compliance with all regulatory constraints that allowed 

commencement of the operation.

The primary objective of an initial inspection is to assure proper installation of mobile drilling 

units and fixed structures, and proper functionality of their safety and pollution prevention equipment. 

After operations begin, additional announced and unannounced inspections are conducted. 

Unannounced inspections are conducted to foster a climate of safe operations, to maintain a BSEE 

presence, and to focus on operators with a poor performance record. These inspections are also

conducted after a critical safety feature has previously been found defective. Poor performance 

generally means that more frequent, unannounced inspections may be conducted on a violator’s 

operation.

The annual inspection examines all safety equipment designed to prevent blowouts, fires, 

spills, or other major accidents. These annual inspections involve the inspection for installation and 

performance of all facilities’ safety-system components.

The inspectors follow the guidelines as established by the regulations, API RP 14C, and the 

specific BSEE-approved plan. The BSEE inspectors perform these inspections using a national 
Postlease Permitting and Approval Processes A-17

checklist called the Potential Incident of Noncompliance list. This list is a compilation of yes/no 

questions derived from all regulated safety and environmental requirements.

The BSEE administers an active civil penalties program (30 CFR part 250 subpart N). A civil 

penalty in the form of substantial monetary fines may be issued against any operator that commits a 

violation that may constitute a threat of serious, irreparable, or immediate harm or damage to life, 

property, or the environment. The BSEE may make recommendations for criminal penalties if a 

willful violation occurs. In addition, the regulation at 30 CFR § 250.173(a) authorizes suspension of 

any operation in the Gulf of Mexico region if the lessee has failed to comply with a provision of any 

applicable law, regulation, or order or provision of a lease or permit. Furthermore, the Secretary 

may invoke his authority under 30 CFR § 550.185(c) to cancel a nonproductive lease with no 

compensation. Exploration and development activities may be canceled under 30 CFR §§ 550.182 

and 550.183.

A.5 POLLUTION PREVENTION, OIL-SPILL RESPONSE PLANS, AND FINANCIAL 

RESPONSIBILITY

Pollution Prevention

Pollution prevention is addressed through proper design and requirements for safety 

devices. The BSEE regulations at 30 CFR § 250.401 require that the operator take all necessary 

precautions to keep its wells under control at all times. The lessee is required to use the best 

available and safest drilling technology in order to enhance the evaluation of conditions of abnormal 

pressure and to minimize the potential for the well to flow or kick. Redundancy is required for critical 

safety devices that will shut off flow from the well if loss of control is encountered.

In addition, BSEE’s regulations at 30 CFR part 250 subparts E, F, and H require that the 

lessee assure the safety and protection of the human, marine, and coastal environments during 

completion, workover, and production operations. All production facilities, including separators, 

treaters, compressors, headers, and flowlines are required to be designed, installed, tested, 

maintained, and used in a manner that provides for efficiency, safety of operations, and protection of 

the environment. Wells, particularly subsea wells, include a number of sensors that help in detecting 

pressures and the potential for leaks in the production system. Safety devices are monitored and 

tested frequently to ensure their operation, should an incident occur. To ensure that safety devices 

are operating properly, BSEE incorporates the API RP 14C into the operating regulations. The API 

RP 14C incorporates the knowledge and experience of the oil and gas industry regarding the 

analysis, design, installation, and testing of the safety devices used to prevent pollution. The API 

RP 14C presents proven practices for providing these safety devices for offshore production 

platforms. Proper application of these practices, along with good design, maintenance, and 

operation of the entire production facility, should provide an operationally safe and pollution-free 

production platform.

Also, BSEE’s regulations at 30 CFR part 250 subpart J require that pipelines and associated 

valves, flanges, and fittings be designed, installed, operated, and maintained to provide safe and 
A-18 Gulf of Mexico Multisale EIS

pollution-free transportation of fluids in a manner that does not unduly interfere with other uses on 

the OCS.

The BSEE regulation at 30 CFR § 250.300(a) requires that lessees not create conditions that 

will pose an unreasonable risk to public health, life, property, aquatic life, wildlife, recreation, 

navigation, commercial fishing, or other uses of the ocean during offshore oil and gas operations. 

The lessee is required to take measures to prevent the unauthorized discharge of pollutants into the 

offshore waters. Control and removal of pollution is the responsibility and at the expense of the 

lessee. Immediate corrective action in response to an unauthorized release is required. All 

hydrocarbon-handling equipment for testing and production, such as separator and treatment tanks, 

is required to be designed, installed, and operated to prevent pollution. Maintenance and repairs 

that are necessary to prevent pollution are required to be taken immediately. Drilling and production 

facilities are required to be inspected daily or at intervals approved or prescribed by BSEE’s District 

Field Operations Supervisor to determine if pollution is occurring.

Operators are required to install curbs, gutters, drip pans, and drains on platform and rig 

deck areas in a manner necessary to collect all greases, contaminants, and debris not authorized for 

discharge. The rules also explicitly prohibit the disposal of equipment, cables, chains, containers, or 

other materials into offshore waters. Portable equipment, spools or reels, drums, pallets, and other 

loose items must be marked in a durable manner with the owner’s name prior to use or transport 

over offshore waters. Smaller objects must be stored in a marked container when not in use. 

Operational discharges such as produced water and drilling muds and cuttings are regulated by the 

USEPA through the National Pollutant Discharge Elimination System permit program for new and 

existing discharges and sources (40 CFR part 435 subpart A). The BSEE may restrict the rate of 

drilling fluid discharge or prescribe alternative discharge methods. No petroleum-based substances, 

including diesel fuel, may be added to the drilling mud system without prior approval of BSEE’s 

District Field Operations Supervisor.

Oil-Spill Response Plans

The BSEE regulations at 30 CFR part 254 require that all owners and operators of oilhandling, storage, or transportation facilities located seaward of the coastline submit an oil-spill 

response plan (OSRP) for approval. The term “coastline” means the line of ordinary low water along 

that portion of the coast that is in direct contact with the open sea and the line marking the seaward 

limit of inland waters. The term “facility” means any structure, group of structures, equipment, or 

device (other than a vessel), which is used for one or more of the following purposes: exploring for; 

drilling for; producing; storing; handling; transferring; processing; or transporting oil. A mobile 

offshore drilling unit is classified as a facility when engaged in drilling or downhole operations.

The regulation at 30 CFR § 254.2 requires that an OSRP must be submitted and approved 

before an operator can use a facility. The BSEE can grant an exception to this requirement during 

BSEE’s review of an operator’s submitted OSRP. In order to be granted this exception during this 

time period, an owner/operator must certify in writing to BSEE that it is capable of responding to a 
Postlease Permitting and Approval Processes A-19

“worst-case” spill or the substantial threat of such a spill. To continue operations, the facility must be 

operated in compliance with the approved OSRP or BSEE-accepted “worst-case” spill certification. 

Owners or operators of offshore pipelines are required to submit an OSRP for any pipeline that 

carries oil, condensate, or gas with condensate; pipelines carrying essentially dry gas do not require 

an OSRP. Current OSRPs are required for abandoned facilities until they are physically removed or 

dismantled.

The OSRP describes how an operator intends to respond to an oil spill. The OSRP may be 

site-specific or regional (30 CFR § 254.3). The term “regional” means a spill response plan that 

covers multiple facilities or leases of an owner or operator, including affiliates, which are located in 

the same BSEE Gulf of Mexico region. The subregional plan concept is similar to the regional 

concept, which allows leases or facilities to be grouped together for the purposes of (1) calculating 

response times, (2) determining quantities of response equipment, (3) conducting oil-spill trajectory 

analyses, (4) determining worst-case discharge scenarios, and (5) identifying areas of special 

economic and environmental importance that may be impacted and the strategies for their 

protection. The number and location of the leases and facilities allowed to be covered by a 

subregional OSRP will be decided by BSEE on a case-by-case basis considering the proximity of 

the leases or facilities proposed to be covered. The NTL 2012-N06 includes guidance on the 

preparation and submittal of regional OSRPs.

The Emergency Response Action Plan within the OSRP serves as the core of BSEErequired OSRPs. In accordance with 30 CFR part 254, the Emergency Response Action Plan 

requires identification of (1) the qualified individual and the spill-response management team, (2) the 

spill-response operating team, (3) the oil-spill cleanup organizations under contract for response, 

and (4) the Federal, State, and local regulatory agencies that an owner/operator must notify or that 

they must consult with to obtain site-specific environmental information when an oil spill occurs. The 

OSRP is also required to include an inventory of appropriate equipment and materials, their 

availability, and the time needed for deployment, as well as information pertaining to dispersant use, 

in-situ burning, a worst-case discharge scenario, contractual agreements, training and drills, 

identification of potentially impacted environmental resources and areas of special economic 

concern and environmental importance, and strategies for the protection of these resources and 

areas. The response plan must provide for response to an oil spill from the facility, and the operator 

must immediately carry out the provisions of the plan whenever an oil spill from the facility occurs. 

The OSRP must be in compliance with the National Contingency Plan and the Area Contingency 

Plan(s). The operator is also required to carry out the training, equipment testing, and periodic drills 

described in the OSRP. All BSEE-approved OSRPs must be reviewed at least every 2 years. In 

addition, revisions must be submitted to BSEE within 15 days whenever

• a change occurs that appreciably reduces an owner/operator’s response 

capabilities;

• a substantial change occurs in the worst-case discharge scenario or in the type 

of oil being handled, stored, or transported at the facility;
A-20 Gulf of Mexico Multisale EIS

• there is a change in the name(s) or capabilities of the oil-spill removal 

organizations cited in the OSRP; or

• there is a change in the applicable Area Contingency Plans.

As a result of the Deepwater Horizon explosion and oil spill, although BSEE is not requiring 

the submission of revised OSRPs at this time, BSEE will provide guidance regarding additional 

information that operators should submit regarding spill response and surface containment in light of 

the “worst-case” discharge calculations that are now required by the regulations and as clarified in 

NTL 2010-N06, “Information Requirements for Exploration Plans, Development and Production 

Plans, and Development Operations Coordination Documents on the OCS,” which became effective 

on June 18, 2010. This NTL provides clarification of the regulations requiring a lessee or operator to 

submit supplemental information for new or previously submitted EPs, DPPs, or DOCDs. The 

required supplemental information includes the following: (1) a description of the blowout scenario 

as required by 30 CFR §§ 550.213(g) and 550.243(h); (2) a description of their assumptions and 

calculations used in determining the volume of the worst-case discharge required by 30 CFR § 

550.219(a)(2)(iv) (for EPs) or 30 CFR § 550.250(a)(2)(iv) (for DPPs and DOCDs); and (3) a 

description of the measures proposed that would enhance the ability to prevent a blowout, to reduce 

the likelihood of a blowout, and to conduct effective and early intervention in the event of a blowout, 

including the arrangements for drilling relief wells and any other measures proposed. The early 

intervention methods could actually include the surface and subsea containment resources that 

BSEE announced in NTL 2010-BSEE-N10, “Statement of Compliance with Applicable Regulations 

and Evaluation of Information Demonstrating Adequate Spill Response and Well Containment 

Resources,” which states that BSEE will begin reviewing to ensure that the measures are adequate 

to promptly respond to a blowout or other loss of well control.

Additionally, to address new improved containment systems, NTL 2010-N10 became 

effective on November 8, 2010. This NTL applies only to operators conducting operations using 

subsea or surface BOPs on floating facilities. It clarifies the regulations that lessees and operators 

must submit a certification statement signed by an authorized company official with each application 

for a well permit, indicating that they will conduct all of their authorized activities in compliance with 

all applicable regulations, including the Increased Safety Measures Regulations (Federal Register, 

2010). The NTL also informs lessees that BSEE will be evaluating whether or not each operator has 

submitted adequate information demonstrating that it has access to and can deploy surface and 

subsea containment resources that would be adequate to promptly respond to a blowout or other 

loss of well control. Although the NTL does not provide that operators submit revised OSRPs that 

include this containment information at this time, operators were notified of BSEE’s intention to 

evaluate the adequacy of each operator to comply in the operator’s current OSRP; therefore, there is 

an incentive for voluntary compliance.

The following requirements are implemented according to BSEE’s regulations at 30 CFR 

parts 250 and 254:
Postlease Permitting and Approval Processes A-21

• requires immediate notification for spills >1 bbl—all spills require notification to 

USCG, and BSEE receives notification from the USCG of all spills ≥1 bbl;

• conducts investigations to determine the cause of a spill;

• assesses civil and criminal penalties, if needed;

• oversees spill source control and abatement operations by industry;

• sets requirements and reviews and approves OSRPs for offshore facilities;

• conducts unannounced drills to ensure compliance with OSRPs;

• requires operators to ensure that their spill-response operating and management 

teams receive appropriate spill-response training;

• conducts inspections of oil-spill response equipment;

• requires industry to show financial responsibility to respond to possible spills; and

• provides research leadership to improve the capabilities for detecting and 

responding to an oil spill in the marine environment.

BOEM receives and reviews the worst-case discharge and blowout scenarios information 

submitted for EPs, DPPS, and DOCDs on the OCS. BOEM also has regulatory requirements 

addressing site-specific OSRPs and spill response information. As required by BOEM at 30 CFR §§ 

550.219 and 550.250, operators are required to provide BOEM with an OSRP that is prepared in 

accordance with 30 CFR part 254 subpart B with their proposed exploration, development, or 

production plan for the facilities that they will use to conduct their activities; or to alternatively 

reference their approved regional OSRP by providing the following information:

• a discussion of the approved OSRP;

• the location of the primary oil-spill equipment base and staging area;

• the name of the oil-spill equipment removal organization(s) for both equipment 

and personnel;

• the calculated volume of the worst-case discharge scenario in accordance with 

30 CFR § 254.26(a) and a comparison of the worst-case discharge scenario in 

the approved regional OSRP with the worst-case discharge calculated for these 

proposed activities; and

• a description of the worst-case discharge to include the trajectory information, 

potentially impacted resources, and a detailed discussion of the spill response 

proposed to the worst-case discharge in accordance with 30 CFR §§ 254(b)-(d).

All OSRPs are reviewed and approved by BSEE, whether submitted with a BOEMassociated plan or directly to BSEE in accordance with 30 CFR part 254. Hence, BOEM relies 
A-22 Gulf of Mexico Multisale EIS

heavily upon BSEE’s expertise to ensure that the OSRP complies with all pertinent laws and 

regulations, and demonstrates the ability of an operator to respond to a worst-case discharge. The 

operator is also required to carry out the training, equipment testing, and periodic drills described in 

the OSRP. Since 1989, BSEE has conducted government initiated unannounced exercises that 

provide an economically feasible mechanism for agencies to comply with the requirements defined 

in 30 CFR part 254. In 2014, BSEE carried out seven table-top, government-initiated unannounced 

exercises and two deployment government-initiated unannounced exercises (USDOI, BSEE, 2014). 

Equipment deployment exercises most often take place in waterways adjacent to where the 

equipment is stored, but they may be moved if the exercise requires it. Typical deployment 

exercises last only a few hours and rarely longer than a day (USDOI, BSEE, official communication, 

2015). Site-specific OSRPs are required to be submitted to BOEM with a proposed exploration, 

development, or production plan, and BOEM’s regulations require that an operator must have an 

approved OSRP prior to BOEM’s approval of an operator-submitted exploration, development, or 

production plan.

Several NTLs and guidance documents have been issued by BOEM and BSEE that clarify 

additional oil-spill requirements since the occurrence of the Deepwater Horizon explosion, oil spill, 

and response. The following is a summary of that information.

Worst-Case Discharge and Blowout Scenario Information

NTL 2015-BOEM-N01

BOEM issued NTL 2015-BOEM-N01, “Information Requirements for Exploration Plans, 

Development and Production Plans, and Development Operations Coordination Documents on the 

OCS for Worst Case Discharge and Blowout Scenarios”. This NTL became effective on January 4, 

2015, and explains the procedures for the lessee or operator to submit worst-case discharge and 

blowout scenario information for new or previously submitted EPs, DPPs, or DOCDs. This NTL 

supersedes NTL 2010-N06, “Information Requirements for Exploration Plans, Development and 

Production Plans, and Development Operations Coordination Documents on the OCS.” The 

required information to be submitted for new EPs, DPPs, and DOCDs or as a supplement to a 

previously submitted plan includes the following: (1) a blowout scenario as required by 30 CFR §§

550.213(g) and 550.243(h); (2) a description of their assumptions and calculations used in 

determining the volume of the worst-case discharge required by 30 CFR § 550.219(a)(2)(iv) (for 

EPs) or 30 CFR § 550.250(a)(2)(iv) (for DPPs and DOCDs); and (3) a description of the measures 

proposed that would enhance the ability to prevent a blowout, to reduce the likelihood of a blowout, 

and to conduct effective and early intervention in the event of a blowout, including the arrangements 

for drilling relief wells and any other measures proposed.

BOEM also issued NTL 2015-BOEM-N01 “Frequently Asked Questions Information Sheet for 

Information Requirements for Exploration Plans, Development and Production Plans, and 

Development Operations Coordination Documents on the OCS for Worst Case Discharge and 

Blowout Scenarios”. This Frequently Asked Questions information sheet provides guidance 

intended to assist an operator’s compliance with the worst-case discharge and blowout scenario 
Postlease Permitting and Approval Processes A-23

information requirements pursuant to NTL 2015-BOEM-N01 and also provides information regarding 

BOEM’s review of the submitted information.

NTL 2013-BSEE-N02

The BSEE issued NTL 2013-BSEE-N02, “Significant Change to Oil Spill Response Plan 

Worst Case Discharge Scenario.” This NTL clarifies what BSEE considers a significant change in a 

worst-case discharge scenario, which requires that a revision to an OSRP be submitted. The 

guidance issued by this NTL states that a significant change in worst-case discharge may occur 

when calculating a new worst-case discharge based upon the following:

• the addition of a new facility installation or well;

• a modification to an existing facility; or

• a change in any assumptions and calculations used to determine the prior 

estimated worst-case discharge.

The NTL 2013-BSEE-N02 identifies the process an owner or operator of a facility should 

utilize to determine whether the newly calculated worst-case discharge represents a significant 

change. The BSEE considers a change in worst-case discharge as significant and thus requiring 

revision when the process identifies the need for additional onshore or offshore response equipment 

beyond what is included in an approved OSRP. Although information to make this determination is 

submitted to BOEM and forwarded to BSEE with a proposed exploration, development, or 

production plan, pursuant to NTL 2013-BSEE-N02, the 15-day timeframe for notification of a 

significant change will be enforced by BSEE as beginning no later than the date that the operator 

submitted an Application for Permit to Drill to BSEE.

Typically, for OSRP revisions, once BSEE approves an OSRP, it must be reviewed at least 

every 2 years, and modifications must be submitted in accordance with 30 CFR § 254.30(a). If no 

modifications are deemed necessary, the owner or operator must inform BSEE in writing that there 

are no changes. A separate revision to an OSRP must be submitted to BSEE within 15 days when 

the following conditions are met:

• there is a change that significantly reduces operator response capabilities;

• a significant change occurs in the worst-case discharge or in the type of oil being 

handled, stored, or transported at a facility;

• there is a change in the names or capabilities of the oil-spill removal 

organizations cited in the plan; or

• there is a significant change to the Area Contingency Plan.
A-24 Gulf of Mexico Multisale EIS

NTL 2012-BSEE-N06

The BSEE also issued NTL 2012-BSEE-N06, “Guidance to Owners and Offshore Facilities 

Seaward of the Coast Line Concerning Regional Oil Spill Response Plans.” This NTL, which was 

effective on August 10, 2012, provides clarification, guidance, and information concerning the 

preparation and submittal of a regional OSRP for owners and operators of oil handling, storage, or 

transportation facilities, including pipelines located seaward of the coastline. A regional OSRP is 

defined as a spill response plan covering multiple facilities or leases of an owner, or operator, or 

their affiliates, which are located in the same BSEE region. Site-specific OSRPs submitted with 

BOEM exploration, development, or production plans can either be prepared using the 30 CFR part 

254 regulations or the guidance outlined in NTL 2012-BSEE-N06.

Some of the clarifications and encouraged practices identified in NTL 2012- BSEE-N06 are 

based upon lessons learned from the Deepwater Horizon oil-spill response. This NTL indicates that 

BSEE’s review of OSRPs would also be based, in part, upon information obtained during the 

Deepwater Horizon oil-spill response. For example, during the Deepwater Horizon oil-spill response, 

it was discovered that the total estimated de-rated recovery capacity for all equipment listed in the 

OSRP overestimated the amount of oil that could be removed from the water. The NTL 2012-BSEEN06 therefore states that the OSRP should be developed considering (1) a fully developed response 

strategy that includes the identification of the available dedicated recovery equipment as well as the 

actual operating characteristics of the systems associated with each skimmer and (2) the use of new 

technology and response systems that will increase the effectiveness of mechanical recovery tactics.

The NTL 2012-BSEE-N06 is designed to encourage owners and operators of offshore 

facilities to include innovative offshore oil-spill response techniques, particularly for a continuous 

high-rate spill. This NTL includes requirements for the submittal of information regarding subsea 

containment equipment and subsea dispersant application among other provisions. This NTL also

encourages the inclusion of options that would improve spill-response capabilities such as:

• using remote-sensing techniques as a tool for safe night operations to increase 

oil-spill detection and to improve thickness determinations for ascertaining the 

effectiveness of response strategies;

• increasing spill-response operational time by reducing transit times to disposal 

locations and decontamination equipment;

• identifying sources for supplies and materials, such as fire boom and 

dispersants, that can support a response to an uncontrolled spill lasting longer 

than 30 days or for the duration of the spill response; and

• the use and specification of primary and secondary communications technology 

and software for coordinating and directing spill-response operations systems 

and/or providing a common operating picture to all spill management and 

response personnel, including the Federal On-Scene Coordinator and 

participating Federal and State government officials.
Postlease Permitting and Approval Processes A-25

NTL 2012-BSEE-N07

The BSEE issued NTL 2012-BSEE-N07, “Oil Discharge Written Follow-up Reports.” This 

NTL addresses the oil discharge reports (30 CFR § 254.46(b)(2)) that are required to be submitted 

by a responsible party to BSEE for spills >1 bbl within 15 days after a spill has been stopped or 

ceased. The responsible party is encouraged to report cause, location, volume, remedial action 

taken, sea state, meteorological conditions, and the size and appearance of the slick.

NTL 2010-N10

The Bureau of Ocean Energy Management, Regulation and Enforcement issued NTL 

2010-N10, “Statement of Compliance with Applicable Regulations and Evaluation of Information 

Demonstrating Adequate Spill Response and Well Containment Resources,” which became effective 

on November 8, 2010. This NTL applies only to operators conducting operations using subsea or 

surface BOPs on floating facilities. It explains that lessees and operators submit a statement signed 

by an authorized company official with each application for a well permit indicating that they will 

conduct all of their authorized activities in compliance with all applicable regulations, including the 

Increased Safety Measures Regulations (Federal Register, 2010). The NTL also informs lessees 

that BOEM will be evaluating whether or not each operator has submitted adequate information 

demonstrating that it has access to and can deploy surface and subsea containment resources that 

would be adequate to promptly respond to a blowout or other loss of well control. The NTL notifies 

the operator that BOEM intends to evaluate the adequacy of each operator to comply in the 

operator’s current OSRP; therefore, there is an incentive for voluntary compliance. The NTL lists the 

type of information that BOEM would review as follows:

• subsea containment and capture equipment, including containment domes and 

capping stacks;

• subsea utility equipment, including hydraulic power, hydrate control, and 

dispersant injection equipment;

• riser systems;

• remotely operated vehicles;

• capture vessels;

• support vessels; and

• storage facilities.

Spill Response Initiatives

For more than 25 years, BSEE and its predecessors have maintained a comprehensive longterm research program to improve oil-spill response knowledge and technologies. The major focus 

of the program is to improve the methods and technologies used for oil-spill detection, containment, 

treatment, recovery, and cleanup. The BSEE Oil Spill Response Research program is a cooperative 
A-26 Gulf of Mexico Multisale EIS

effort bringing together funding and expertise from research partners in State and Federal 

government agencies, industry, academia, and the international community. The projects funded 

cover numerous spill response-related issues such as chemical treating agents; in-situ burning of oil; 

research conducted at BSEE’s Oil Spill Response Test Facility (Ohmsett) located in Leonardo, New 

Jersey; behavior of oil; decisionmaking support tools; mechanical containment; and remote sensing.

A few of BSEE’s research contracts that highlight the varied types of research funded include 

the following:

• “Leveraging Offshore Hydrocarbon Risk Assessment Models and Datasets to 

Support the Evaluation and Ranking of Worst Case Discharge Scenarios” 

(Project Number 1046) – The objective of this project is to develop a set of 

methodologies and algorithms, and a computer model for the comparison and 

ranking of different spill scenarios to determine which one has the greater 

potential for damage to the environment or result in other significant impacts and 

should be classified as the worst-case discharge.

• “Scientifically Based Field Tools for Predicting Dispersant Effectiveness and 

Usage Rates” (Project Number 1043) – This project will bridge the gap between 

laboratory methodology and field analysis by incorporating the modified 1-liter 

Baffled Flask Test and fluorescence probe for determining dispersant 

effectiveness in the field.

• “Technology Readiness Level (TRL) Definitions for Oil Spill Response 

Technologies and Equipment” (Project Number 1042) – The objective of this 

study is to establish a uniform and objective means to determine the level of 

maturity of a new technology and when it is ready for use in the field.

• “HC-Sentinel: An AUV Glider for High Endurance Subsea Hydrocarbon 

Detection” (Project Number 1041) – The objective of this study is to develop and 

test a next generation in-situ mass spectrometer payload that operates on an 

autonomous underwater vehicle glider for real-time subsea hydrocarbon 

detection and classification and that can be designed to operate for long-term 

subsea inspection, monitoring, and incident response.

More information on these and the other awarded and completed research projects can be 

found on BSEE’s website at http://www.bsee.gov/Technology-and-Research/Research/. 

Incident Reporting

The Minerals Management Service (MMS) (BOEM’s predecessor) revised operator incident 

reporting requirements in a final rule effective July 17, 2006 (Federal Register, 2006). The incident 

reporting rule defines what incidents must be reported, includes incidents that have the potential to 

be serious, and requires the reporting of standard information for both oral and written reports. As 

part of the incident reporting rule, BOEM’s regulations at 30 CFR § 250.188(a)(6) require an 
Postlease Permitting and Approval Processes A-27

operator to report all collisions that result in property or equipment damage greater than $25,000. 

“Collision” is defined as the act of a moving vessel (including an aircraft) striking another vessel or 

striking a stationary vessel or object (e.g., a boat striking a drilling rig or platform).

Financial Responsibility

The responsible party for covered offshore facilities must demonstrate oil-spill financial 

responsibility, as required by 30 CFR part 553. These regulations implement the oil-spill financial 

responsibility requirements of Title I of the Oil Pollution Act of 1990, as amended. Penalties for 

noncompliance with these requirements are covered at 30 CFR § 553.51 and in NTL 2008-N05, 

“Guidelines for Oil Spill Financial Responsibility for Covered Facilities.” A covered offshore facility, 

as defined in 30 CFR § 553.3, is any structure and all of its components (including wells completed 

at the structure and the associated pipelines), equipment, pipeline, or device (other than a vessel or 

other than a pipeline or deepwater port licensed under the Deepwater Port Act of 1974) used for 

exploring, drilling, or producing oil, or for transporting oil from such facilities. The BSEE ensures that 

each responsible party has sufficient funds for removal costs and damages resulting from the 

accidental release of liquid hydrocarbons into the environment for which the responsible party is 

liable.

A.6 AIR EMISSIONS

The OCSLA (43 U.S.C. § 1334(a)(8)) requires the Secretary of the Interior to promulgate and 

administer regulations that comply with the National Ambient Air Quality Standards, pursuant to the 

Clean Air Act (42 U.S.C. §§ 7401 et seq.), to the extent that authorized activities significantly affect 

the air quality of any State. Under provisions of the Clean Air Act Amendments of 1990, the USEPA

Administrator has jurisdiction and, in consultation with the Secretary of the Interior and the 

Commandant of the Coast Guard, established the requirements to control air pollution in OCS areas 

of the Pacific, Atlantic, Arctic, and eastward of 87.5° W. longitude in the Gulf of Mexico. Air quality in 

the OCS area westward of 87.5° W. longitude in the Gulf of Mexico is under BOEM’s jurisdiction.

For OCS air emission sources located east of 87.5° W. longitude and within 25 mi (40 km) of 

the States’ seaward boundaries, the requirements are the same as would be applicable if the source 

were located in the corresponding onshore area. The USEPA requirements for these OCS areas 

are at 40 CFR part 55, Appendix A. For air emission sources located east of 87.5° W. longitude and 

more than 25 mi (40 km) from the States’ seaward boundaries, sources are subject to Federal 

requirements as specified in 40 CFR § 52.13. The USEPA regulations also establish procedures 

that allow the USEPA Administrator to exempt any OCS source from an emissions control 

requirement if it is technically infeasible or poses unreasonable threat to health or safety.

This Agency issued NTL 2009-N11 to clarify that its regulatory authority and BOEM’s 

implementing regulations in 30 CFR part 250 subpart C and 30 CFR part 550 apply only to those air 

emission sources in the Gulf of Mexico westward of 87.5° W. longitude. The regulated pollutants 

include carbon monoxide, total suspended particulate matter, sulphur dioxide, nitrogen oxides, and 

volatile organic compounds. All new or supplemental EPs and DOCDs must include air emissions 
A-28 Gulf of Mexico Multisale EIS

information sufficient to determine whether an air quality review is required (30 CFR §§ 550.218 and 

550.249). BOEM’s regulations require a review of air quality emissions to determine if the projected 

emissions from a facility result in onshore ambient air concentrations above BOEM’s significance 

levels and to identify appropriate emissions controls to mitigate potential onshore air quality 

degradation.

Emissions data for new or modified onshore facilities directly associated with proposed OCS 

oil- and gas-related activities are required to be included in development plans submitted to BOEM 

so that affected States can determine potential air quality impacts on their air quality.

BOEM uses a two-level hierarchy of evaluation criteria to evaluate potential impacts of 

offshore emission sources to onshore areas. The evaluation criteria are the exemption level and the 

significance level. If the proposed activities exceed the criteria at the first (exemption) level, the 

evaluation moves to the significance level criteria. The initial evaluation compares the worst-case 

emissions with BOEM’s exemption criteria. This corresponds to the USEPA’s screening step, where 

the proposed activity emissions are checked against the screening thresholds or “exemption levels.” 

If the proposed activity’s emissions are below the exemption levels, the proposed activity is exempt 

from further air quality review.

If exemption levels are exceeded, then the second step requires refined modeling using the 

Offshore and Coastal Dispersion (OCD) Model or the California Puff Model (CALPUFF). The results 

from these models, the modeled potential onshore impacts, are compared with BOEM’s significance 

levels. If the significance levels are exceeded in an attainment area, which is an area that meets the 

National Ambient Air Quality Standards, the operator would be required to apply best available 

control technology to the emissions source. If the affected area is classified as nonattainment, 

further emission reductions or offsets may be required. Projected contributions to onshore pollutant 

concentrations are also subject to the same increments that the USEPA applies to the onshore 

areas under their Prevention of Significant Deterioration program.

A.7 FLARING/VENTING

Flaring is the controlled burning of natural gas, and venting is releasing gas directly into the 

atmosphere without burning (refer to Chapter 3.1.8.4). The BSEE regulates flaring/venting to 

minimize the loss of revenue producing natural gas resources. The BSEE regulations at 30 CFR 

part 250 allow, without prior BSEE approval, flaring or venting of natural gas on a limited basis under 

certain specified conditions. Regulations permit more extensive flaring/venting with prior approval 

from BSEE. Records must always be prepared by the operator for all flaring/venting, and 

justification must be provided for flaring/venting not expressly authorized by BSEE’s regulations.

A.8 HYDROGEN SULFIDE CONTINGENCY PLANS

The operator of a lease must request a BSEE area classification for the presence of 

hydrogen sulfide (H2S) gas. The BSEE classifies areas for proposed operations as (1) H2S absent, 

(2) H2S present, or (3) H2S unknown.
Postlease Permitting and Approval Processes A-29

All OCS operators must provide information about potential contact with sour hydrocarbons 

(contains H2S) that could result in atmospheric H2S concentrations above 20 parts per million in their 

exploration or development plan. If an area is known to contain H2S or is in an area where H2S 

potential is unknown, operators are required to file an H2S contingency plan with BSEE. This plan 

must include the 30 CFR part 250 requirements that are intended to ensure workers’ safety at the 

production facility and provide contingencies for simultaneous drilling, well-completion, wellworkovers, and production operations. The NTL 2009-G31, “Hydrogen Sulfide (H2S) Requirements,” 

provides clarification, guidance, and information regarding BSEE’s H2S regulations at 30 CFR 

part 250.

A.9 ARCHAEOLOGICAL RESOURCES REGULATION

Bottom-disturbing operations such as well placement, anchoring, and pipelaying activities 

can lead to damage to any resources that reside on or embedded within the seabed, including 

archaeological resources such as historic shipwrecks. The archaeological resources regulations at 

30 CFR § 250.194 and 30 CFR § 550.194 grant authority to BOEM’s and BSEE’s Regional Directors 

to require that an archaeological survey report be submitted with the EP, DOCD, or DPP where 

deemed necessary. The technical requirements of the high-resolution geophysical survey, 

archaeological analysis, and report are detailed in NTL 2005-G07, “Archaeological Resource 

Surveys and Reports.” If data from the operator’s high-resolution geophysical survey and 

archaeological report suggest that an archaeological resource may be present, the lessee must 

either locate the site of any operation so as not to adversely affect the area of the seafloor identified 

for archaeological avoidance, demonstrate that the identified geophysical target is not an 

archaeological resource through remotely operated vehicle or diver investigation, or demonstrate 

that potential archaeological resources will not be adversely affected by operations. If the lessee 

discovers any archaeological resource while conducting approved operations, operations must be 

immediately stopped and the discovery reported to BOEM’s Regional Supervisor, Office of 

Environment, within 48 hours of its discovery.

High-resolution surveys, where required, provide an effective tool that analysts use to identify 

and help protect archaeological resources. As part of the environmental reviews conducted for 

postlease activities, all available information will be evaluated regarding the potential presence of 

archaeological resources within a proposed action area to determine if mitigation is warranted.

A.10 COASTAL ZONE MANAGEMENT CONSISTENCY REVIEW AND APPEALS FOR 

POSTLEASE ACTIVITIES

The Coastal Zone Management Act (CZMA) places requirements on any applicant for any 

federally licensed or permitted activities on the OCS (i.e., OCS plans, right-of-way pipelines, 

geological and geophysical surveys, and decommissioning) affecting any coastal use or resource, in 

or outside of a State’s coastal zone. The applicant must provide a consistency certification and 

necessary data and information for the State to determine that the proposed activities comply with 

the enforceable policies of the State’s CMP, approved by NOAA, and that such activities will be fully 

consistent with those enforceable policies (16 U.S.C. § 1456(c)(3)(A) and 15 CFR § 930.76).
A-30 Gulf of Mexico Multisale EIS

Except as provided in 15 CFR § 930.60(a), State agency consistency review begins when 

the State receives the OCS plan or application, consistency certification, and necessary data and 

information pursuant to 15 CFR §§ 930.76(a) and (b). Only missing information can be used to 

delay the commencement of State agency review, and a request for information and data that are 

not required by 15 CFR § 930.76 will not extend the date of commencement of review (15 CFR § 

930.58). The information requirements for CZM purposes are found at 30 CFR §§ 550.226 and 

550.260 and are discussed in NTL 2012-BSEE-N06, “Guidance to Owners and Operators of 

Offshore Facilities Seaward of the Coast Line Concerning Regional Oil Spill Response Plans” ; NTL 

2008-G04, “Information Requirements for Exploration Plans and Development Operations 

Coordination Documents”; NTL 2009-G27, “Submitting Exploration Plans and Development 

Operations Coordination Documents”; NTL 2015-BOEM-N01, “Information Requirements for 

Exploration Plans, Development and Production Plans, and Development Operations Coordination 

Documents on the OCS for Worst Case Discharge and Blowout Scenarios”; NTL 2010-N10, 

“Statement of Compliance with Applicable Regulations and Evaluation of Information Demonstrating 

Adequate Spill Response and Well Containment Resources”; and NTL 2007-G20, “Coastal Zone 

Management Program Requirements for OCS Right-of-Way Pipeline Applications.”

All of the Gulf Coast States have federally approved CMP’s. Requirements for the CZM 

consistency information for Texas, Louisiana, Mississippi, Alabama, and Florida are given in NTL’s 

2012-BSEE-N06, 2008-G04, 2009-G27, 2015-BOEM-N01, 2010-N10, and 2007-G20. In 

accordance with the requirements of 15 CFR § 930.76, BOEM’s Gulf of Mexico OCS Region sends 

copies of an OCS plan, including the consistency certification and other necessary data and 

information, to the designated State CMP agency by receipted mail or other approved 

communication. In accordance with the requirements of 15 CFR § 930.60, the applicants are 

responsible for sending the State CMP agency a copy of the applicant, consistency certification, and 

necessary data and information at the same time as when the applicant sends it to BOEM or BSEE. 

If no State-agency objection is submitted by the end of the consistency review period, BOEM shall 

presume consistency concurrence by the CZMA State (15 CFR § 930.78(b)). BOEM can require 

modification of a plan or application.

If BOEM receives a written consistency objection from the State, BOEM and/or BSEE will not 

approve any activity described in the proposed activity unless (1) the operator amends the 

application to accommodate the objection, concurrence is subsequently received or conclusively 

presumed; (2) upon appeal, the Secretary of Commerce, in accordance with 15 CFR part 930 

subpart H, finds that the proposed activity is consistent with the objectives or purposes of the CZMA 

or is necessary in the interest of national security; or (3) the original objection is declared invalid by 

the courts.

A.11 BEST AVAILABLE AND SAFEST TECHNOLOGIES

To assure that oil and gas exploration, development, and production activities on the OCS 

are conducted in a safe and environmentally sound manner, 43 U.S.C. § 1347(b) of the OCSLA, as 

amended, requires that all OCS technologies and operations use the best available and safest 
Postlease Permitting and Approval Processes A-31

technology (BAST) whenever practical. The BSEE Director may require additional BAST measures 

to protect safety, health, and the environment, if it is economically feasible and the benefits outweigh 

the costs. Conformance to the standards, codes, and practices referenced in or required under the 

authority of 30 CFR part 250 is considered the application of BAST. These standards, codes, and 

practices include requirements for state-of-the-art drilling technology, production safety systems, oil 

and gas well completions, oil-spill response plans, pollution-control equipment, and specifications for 

platform/structure designs. The BSEE conducts periodic offshore inspections and continuously and 

systematically reviews OCS technologies to ensure that the best available and safest technologies 

are applied to OCS operations. The BAST is not required when BSEE determines that the 

incremental benefits are clearly insufficient to justify increased costs; however, it is the responsibility 

of an operator of an existing operation to demonstrate why application of a new technology would 

not be feasible. The BAST requirement is applicable to equipment and procedures that, upon 

failure, would have a significant effect on safety, health, or the environment, unless benefits clearly 

do not justify the cost (30 CFR §§ 250.107(c) and (d)).

The BAST concept is addressed in BSEE’s Gulf of Mexico OCS Region by a continuous 

effort to locate and evaluate the latest technologies and to report on these advances at periodic 

Regional Operations Technology Assessment Committee meetings. A part of BSEE’s staff has an 

ongoing function to evaluate various vendors and industry representatives’ innovations and 

improvements in techniques, tools, equipment, procedures, and technologies applicable to oil and 

gas operations (i.e., drilling, producing, completion, and workover operations). This information is 

provided to BSEE’s District personnel at Regional Operations Technology Assessment Committee 

meetings. The requirement for the use of BAST has been, for the most part, an evolutionary 

process whereby advances in equipment, technologies, and procedures have been integrated into 

OCS operations over a period of time. Awareness by both BSEE inspectors and the OCS operators 

of the most advanced equipment and technologies has resulted in the incorporation of these 

advances into day-to-day operations. An example of such an equipment change that evolved over a 

period of time would be the upgrading of diverter systems on drilling rigs from the smaller diameter 

systems of the past to the large-diameter, high-capacity systems found on drilling rigs operating on 

the OCS today.

Production Facilities

The BSEE regulations governing oil and gas production safety systems can be found in 

30 CFR 250 Subpart H. Production safety equipment used on the OCS must be designed, installed, 

used, maintained, and tested in a manner to assure the safety and protection of the human, marine, 

and coastal environments. All tubing installations open to hydrocarbon-bearing zones below the 

surface must be equipped with safety devices that will shut off the flow from the well in the event of 

an emergency, unless the well is incapable of flowing. Surface- and subsurface-controlled safety 

valves and locks must conform to the requirements of 30 CFR § 250.801. All surface production 

facilities, including separator and treatment tanks, compressors, headers, and flowlines must be 

designed, installed, and maintained in a manner that provides for efficiency, safety of operations, 

and protection of the environment. Production facilities also have stringent requirements concerning 
A-32 Gulf of Mexico Multisale EIS

electrical systems, flowlines, engines, and firefighting systems. The safety-system devices are 

tested by the lessee at specified intervals and must be in accordance with API RP 14 C Appendix D 

and other measures.

A.12 PERSONNEL TRAINING AND EDUCATION

An important factor in ensuring that offshore oil and gas operations are carried out in a 

manner that emphasizes operational safety and minimizes the risk of environmental damage is the 

proper training of personnel. Under 30 CFR part 250 subpart O, BSEE has outlined well control and 

production safety training program requirements for lessees operating on the OCS. The goal of the 

regulation (30 CFR § 250.1501) is safe and responsible OCS operations. Lessees must ensure that 

their employees and contract personnel engaged in well control or production safety operations

understand and can properly perform their duties. To accomplish this, the lessee must establish and 

implement a training program so that all of its employees are trained to competently perform their 

assigned well control and production safety duties. The lessee must also verify that its employees 

understand and can perform the assigned duties.

The mandatory Drilling Well-Control Training Program was instituted by this Agency in 1979. 

In 1983, the mandatory Safety Device Training Program was established to ensure that personnel 

involved in installing, inspecting, testing, and maintaining safety devices are qualified. As a 

preventive measure, all offshore personnel must be trained to operate oil-spill cleanup equipment, or 

the lessee must retain a trained contractor(s) to operate the equipment for them. In addition, BSEE 

offers numerous technical seminars to ensure that personnel are capable of performing their duties 

and are incorporating the most up-to-date safety procedures and technology in the petroleum 

industry.

On February 5, 1997, MMS (BOEM’s predecessor) published a final rule in the Federal 

Register (1997) concerning the training of the lessee and contractor employees engaged in drilling, 

well completion, well workover, well serving, or production safety system operations in the OCS. 

The final rule streamlined the previous regulations by 80 percent, provided the flexibility to use 

alternative training methods, and simplified the training options at 30 CFR part 250 subpart O. 

Although the rule did away with many of the onerous requirements in subpart O and served as 

intermediate change to the system, it did not sufficiently address development of a performancebased training system.

On August 14, 2000, MMS (BOEM’s predecessor) published in the Federal Register (2000) 

final regulations revising 30 CFR part 250, subpart O, “Well Control and Production Safety Training.” 

The MMS distributed the published final rulemaking to lessees, operators, and training schools. 

These new performance-based regulations took effect on October 13, 2000. To allow sufficient time 

for lessees to implement their training programs, the rule provided a 2-year transition period from 

October 13, 2000, until October 15, 2002. After October 15, 2002, all lessees were required to be in 

compliance with this rule.
Postlease Permitting and Approval Processes A-33

Goal of Performance Training Rule: Safe and responsible OCS operations. Lessees must 

ensure their employees, including contractors, are trained to competently perform their assigned well 

control and production safety duties. This rule should allow companies to focus their resources on 

important areas in their program rather than on sending all of their personnel to the same school 

program on a routine basis.

Key Elements of Performance Based Training: Under this rule, schools will be free to 

operate but they will not receive agency approval and they will no longer be able to issue subpart O 

certifications. By shifting the responsibility of developing training programs to industry, lessees will 

have to decide upon the type of training for their employees. The BSEE will hold the lessees 

responsible for the success or failure of these and other training related decisions.

Lessees Training Plan: The lessees’ training plan is the core item of BSEE’s performancebased program. The plan, which does not have to be approved by BSEE, lays out the company’s 

training philosophy. It must specify the type, method(s), length, frequency, and content of their 

program. Training requirements under this rule are limited to only well control and production 

operations.

Performance Indicators: The BSEE will periodically assess lessee and contractor training 

programs to see how well their employees are trained. To assess programs, BSEE may use one or 

more of the following evaluation methods: (1) audits; (2) written tests; (3) hands-on tests; and 

(4) employee interviews.

A.13 STRUCTURE REMOVAL AND SITE CLEARANCE

During exploration, development, and production operations, temporary and permanent 

equipment and structures are often required to be embedded into or placed onto the seafloor around 

activity areas. In compliance with Section 22 of BOEM’s Oil and Gas Lease Form (BOEM-2005) and 

OCSLA regulations (30 CFR § 250.1710—Wellheads/Casings and 30 CFR § 250.1725—Platforms 

and Other Facilities), operators need to remove seafloor obstructions from their leases within 1 year 

of lease termination or after a structure has been deemed obsolete or unusable. These regulations 

also require the operator to sever bottom-founded objects and their related components at least 5 m 

(15 ft) below the mudline (30 CFR § 250.1716(a)—Wellheads/Casings and 30 CFR § 250.1728(a)—

Platforms and Other Facilities). The severance operations are generally categorized as explosive or 

nonexplosive.

There are, however, possible exemptions to the 1-year deadline, including the exemptions 

stated in Section 388 of the Environmental Policy Act. Section 388 clarifies the Secretary’s authority 

to allow an offshore oil and gas structure, previously permitted under the OCSLA, to remain in place 

after OCS oil- and gas-related activities have ceased in order to allow the use of the structure for 

other energy- and marine-related activities. This authority provides opportunities to extend the life of 

facilities for non-OCS oil- and gas-related purposes, such as research, renewable energy 

production, aquaculture, etc., before being removed.
A-34 Gulf of Mexico Multisale EIS

This Agency previously addressed removal operations and the potential impacts of severing 

methodologies (nonexplosive/explosive tools) in a Programmatic EA prepared in 1987 (USDOI, 

MMS, 1987). The scope of the decommissioning activities analyzed in the Programmatic EA was 

limited to traditional, bottom-founded structures (i.e., well protectors, caissons, and jacketed 

platforms) and did not address well abandonment operations; activities similar in nature, but 

monitored and reported according to a separate section of the OCSLA regulations. In addition, since 

the majority of removal operations took place in water depths >200 m (656 ft), only the shelf areas of 

the CPA and WPA were addressed by the proposed actions. 

In response to advancements in decommissioning methodologies and regulatory 

requirements since the 1987 Programmatic EA was prepared, as well as the continued movement 

into more deepwater prospects (>200 m; 656 ft), this Agency prepared Structure-Removal 

Operations on the Gulf of Mexico Outer Continental Shelf: Programmatic Environmental 

Assessment (USDOI, MMS, 2005). This Programmatic EA serves three primary needs:

• aids in the permitting, management, and planning of future structure-removal 

operations;

• ensures that adequate environmental reviews are conducted on all 

decommissioning proposals that would help support human health and safety 

while simultaneously protecting the sensitive marine environment; and

• serves as a reference document to implement the "tiering" objective detailed in 

NEPA’s implementing regulations (40 CFR § 1502.20) (future, site-specific EAs 

may reference appropriate chapters of this Programmatic EA to reduce 

reiteration of issues and impacts, allowing analyses to focus on specific issues 

and impacts related to the removal activity).

In 1988, this Agency requested a “generic” consultation from NMFS pursuant to Section 7 of 

the Endangered Species Act concerning potential impacts on endangered and threatened species 

associated with explosive-severance activities conducted during structure-removal operations. 

Much like the Programmatic EA, the consultation’s “generic” Biological Opinion was limited to the 

best scientific information available and concentrated primarily on the majority of structure removals 

(water depths <200 m [656 ft]). The Incidental Take Statement was therefore limited to the five 

species of sea turtles found on the shallow shelf. Reporting guidelines and specific mitigating 

measures are outlined in the Incidental Take Statement and include (1) the use of a qualified NMFS 

observer, (2) aerial surveys, (3) detonation delay radii, (4) nighttime blast restrictions, (5) charge 

staggering and grouping, and (6) possible diver survey requirements.

Emphasizing a continued need for an incentive to keep explosive weights low, this Agency 

formally requested that NMFS amend the 1988 Biological Opinion to establish a minimum charge 

size of 5 lb. The NMFS’s Southeast Regional Office subsequently addressed explosive charges 

≤5 lb in a separate, informal Biological Opinion. The October 2003 “de-minimus” Biological Opinion 

waives several mitigating measures of the “generic” 1988 Biological Opinion (i.e., aerial 
Postlease Permitting and Approval Processes A-35

observations, 48-hour pre-detonation observer coverage, onsite NOAA personnel, etc.), reduces the 

potential impact zone from 3,000 ft to 700 ft (914 m to 213 m) and gives the operators/severing 

contractors the opportunity to conduct their own observation work.

In 1989, the American Petroleum Institute petitioned NMFS under Subpart A of the Marine 

Mammal Protection Act regulations for the incidental take of spotted and bottlenose dolphins during 

structure-removal operations (i.e., for either explosive- or nonexplosive-severance activities). The 

Incidental Take Authorization regulations were promulgated by NMFS in October 1995 (Federal 

Register, 1995) and on April 10, 1996, the regulations were moved to subpart M (50 CFR §§

216.141 et seq.). Effective for 5 years, the regulations detailed conditions, reporting requirements, 

and mitigating measures similar to those listed in the 1988 ESA Consultation requirements for sea 

turtles. After the regulations expired in November 2000, NMFS and this Agency advised operators 

to continue following the guidelines and mitigating measures of the lapsed subpart pending a new 

petition and subsequent regulations. At industry’s prompting, NMFS released interim regulations in 

August 2002, which expired on February 2, 2004. Operators have continued to follow the interim 

conditions until NMFS promulgates new regulations.

After bottom-founded objects are severed and the structures are removed, operators are 

required to verify that the site is clear of any obstructions that may conflict with other uses of the 

OCS according to 30 CFR §§ 250.1740-1743. The NTL 98-26, “Minimum Interim Requirements for 

Site Clearance (and Verification) of Abandoned Oil and Gas Structures in the Gulf of Mexico,” 

provides the requirements for site clearance. The lessee must develop, and submit to BOEM for 

approval, a procedural plan for the site clearance verification procedures. For platform and caisson 

locations in water depths of <91 m (300 ft), the sites must be trawled over 100 percent of the 

designated area in two directions (i.e., N-S and E-W). Individual well-site clearances may use highfrequency (500 kHz) sonar searches for verification. Site-clearance verification must take place 

within 60 days after structure-removal operations have been conducted.

A NEPA analysis, in the form of an EA or EIS, is completed for all structure removals that 

propose explosive severance methods and/or site clearance trawling. The Marine Protected 

Species NTLs’ discussion below describes regulations, reporting guidelines, and specific mitigating 

measures developed through consultation, pursuant to section 7 of the Endangered Species Act and 

the Marine Mammal Protection Act, concerning potential impacts on endangered and threatened 

species associated with explosive severance activities conducted during the structure-removal 

operations. All of the current terms and conditions of structure and well-removal activities are 

outlined in NTL 2010-G05, “Decommissioning Guidance for Wells and Platforms,” which became 

effective on October 15, 2010.

A.14 MARINE PROTECTED SPECIES NTLS

Four NTLs advise operators of measures designed to reduce impacts to Marine Protected 

Species: NTL 2012-JOINT-G02, “Implementation of Seismic Survey Mitigation Measures and 

Protected Species Observer Program”; NTL 2012-BSEE-G01, “Marine Trash and Debris Awareness 
A-36 Gulf of Mexico Multisale EIS

and Elimination”; NTL 2012-JOINT-G01, “Vessel Strike Avoidance and Injured/Dead Protected 

Species Reporting”; and NTL 2010-G05, “Decommissioning Guidance for Wells and Platforms”. The 

provisions outlined in these NTLs apply to all existing and future oil and gas operations in the Gulf of 

Mexico OCS.

The NTL 2012-JOINT-G02, “Implementation of Seismic Survey Mitigation Measures and 

Protected Species Observer Program,” provides guidance to protect marine mammals and sea 

turtles during seismic operations. This NTL clarifies how operators should implement seismic survey 

mitigating measures (including ramp-up procedures), the use of a minimum sound source, airgun 

testing, and protected species observation and reporting.

The NTL 2012-BSEE-G01, “Marine Trash and Debris Awareness and Elimination,” provides 

information on the marine trash and debris awareness training video and slide show, and both postal 

and email addresses for submitting annual training reports.

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

Reporting,” explains how operators must implement measures to minimize the risk of vessel strikes 

to protected species and report observations of injured or dead protected species.

The NTL 2010-BSEE-G05, “Decommissioning Guidance for Wells and Platforms,” provides 

clarification and interpretation of regulations regarding decommissioning, as well as guidance to 

operators proposing to use explosives to perform well/casing severance. These guidelines specify 

and reference mitigation, monitoring, and reporting requirements that allow explosive charges up to 

500 lb, internal and external placement, and both above-mudline and below-mudline detonations.

A.15 RIGS-TO-REEFS

The BSEE is responsible for permitting the placement and eventual removal of temporary oil 

and gas facilities on the Federal OCS. When an OCS lease expires and/or development and 

production operations cease, companies are obligated to decommission and remove their facilities 

(30 CFR § 250.1725(a)) and clear the seabed of all obstructions (30 CFR § 250.1740). The BSEE’s 

Rigs-to-Reefs Policy provides a means by which lessees may request a waiver to the removal 

requirement. Under 30 CFR § 250.1730, BSEE may grant a departure from the 30 CFR § 

250.1725(a) requirement to remove a platform. Although BSEE supports and encourages the reuse 

of obsolete oil and gas structures as artificial reefs and is a cooperating agency in implementing the 

National Artificial Reef Plan, specific requirements must be met for a departure to be granted. The 

BSEE may allow a departure from removal requirements (30 CFR § 250.1725(a)) and applicable 

lease obligations provided that

• the structure must become part of a State artificial reef program that complies 

with the criteria in the National Artificial Reef Plan (30 CFR § 250.1730(a));
Postlease Permitting and Approval Processes A-37

• the responsible State agency requires a permit from the COE and must accept 

title and liability for the reefed structure once removal/reefing operations are 

concluded (30 CFR § 250.1730(a)); and

• the lessee/operator must satisfy any USCG navigational requirements for the 

reefed structure (30 CFR § 250.1730(b)).

All five Gulf Coast States have active artificial reef programs that develop and manage 

artificial reefs on the Federal OCS. Since the inception of Rigs-to Reef, over 450 decommissioned 

platforms have been donated and deployed as artificial reefs in the Gulf of Mexico.

A.16 REFERENCES

Federal Register. 1995. Incidental take of marine mammals; bottlenose dolphins and spotted 

dolphins. 60 FR 233, pp. 62243-62244. December 5, 1995.

Federal Register. 1997. Training of lessee and contractor employees engaged in oil and gas and 

sulphur operations in the outer continental shelf (OCS). Final rule. 62 FR 24, pp. 5320-5329. 

February 5, 1997.

Federal Register. 2000. Oil and gas and sulphur operations in the outer continental shelf—

Subpart O—Well control and production safety training. Final rule. 65 FR 157, 

pp. 49485-49491. August 14, 2000.

Federal Register. 2005. Oil and gas and sulphur operations in the outer continental shelf-Plans and 

information. Final Rule. 70 FR 167, pp. 51478-51519. August 30, 2005.

Federal Register. 2006. Oil and gas and sulphur operations in the outer continental shelf—Incident 

reporting requirements. Final rule. 71 FR 73, pp. 19640-19646. April 17, 2006.

Federal Register. 2010. Oil and gas and sulphur operations in the outer continental shelf—

Increased safety measures for energy development on the outer continental shelf. Interim final 

rule. 75 FR 198, pp. 63346-63377. October 14, 2010.

Regg, J.B., S. Atkins, B. Hauser, J. Hennessey, B. Kruse, J. Lowenhaupt, B. Smith, and A. White. 

2000. Deepwater development: A reference document for the deepwater environmental 

assessment, Gulf of Mexico OCS (1998 through 2007). U.S. Dept. of the Interior, Minerals 

Management Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS Report MMS 

2000-015. 94 pp.

U.S. Dept. of the Interior. 2010. Increased safety measures for energy development on the outer 

continental shelf, May 27, 2010. U.S. Dept. of the Interior, Washington, DC. 44 pp. Internet 

website: http://loe.org/images/content/100528/Increased-Safety-Measures-Report-2.pdf. 

U.S. Dept. of the Interior. Bureau of Safety and Environmental Enforcement. 2014. Annual report 

2014. Internet website: http://www.bsee.gov/uploadedFiles/BSEE/BSEE_Newsroom/

Publications_Library/Annual_Report/BSEE%202014%20Annual%20Report.pdf. Accessed 

December 2, 2015.
A-38 Gulf of Mexico Multisale EIS

U.S. Dept. of the Interior. Bureau of Safety and Environmental Enforcement. 2015. Official 

communication. Memorandum regarding BSEE’s initiated oil spill response equipment 

deployments – coverage under the National Environmental Policy Act (NEPA) and the 

Endangered Species Act (ESA). November 18, 2015.

U.S. Dept. of the Interior. Minerals Management Service. 1987. Programmatic environmental 

assessment: Structure removal activities, Central and Western Gulf of Mexico Planning Areas. 

U.S. Dept. of the Interior, Minerals Management Service, Gulf of Mexico OCS Region, New 

Orleans, LA. OCS EIS/EA MMS 87-0002. 84 pp.

U.S. Dept. of the Interior. Minerals Management Service. 2000. Gulf of Mexico deepwater 

operations and activities: Environmental assessment. U.S. Dept. of the Interior, Minerals 

Management Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS EIS/EA MMS 

2000-001. 264 pp. Internet website: http://www.boem.gov/BOEM-Newsroom/Library/

Publications/2000/2000-001.aspx. 

U.S. Dept. of the Interior. Minerals Management Service. 2004. Geological and geophysical 

exploration for mineral resources on the Gulf of Mexico outer continental shelf—final 

programmatic environmental assessment. U.S. Dept. of the Interior, Minerals Management 

Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS EIS/EA MMS 2004-054. 466 pp.

U.S. Dept. of the Interior. Minerals Management Service. 2005. Structure-removal operations on 

the outer continental shelf of the Gulf of Mexico—programmatic environmental assessment. 

U.S. Dept. of the Interior, Minerals Management Service, Gulf of Mexico OCS Region, New 

Orleans, LA. OCS EIS/EA MMS 2005-013. 333 pp.
APPENDIX B 

COMMONLY APPLIED MITIGATING MEASURES

Commonly Applied Mitigating Measures B-3 

B COMMONLY APPLIED MITIGATING MEASURES

Postlease mitigating measures have been implemented for over 40 years in the Gulf of 

Mexico region, as they relate to OCS plans and pipeline applications. These mitigating measures 

have been amended over time to address changes in regulations, new technology, and new 

methods of operating. Many of these mitigating measures have been adopted and incorporated into 

regulations and/or guidelines governing OCS oil and gas exploration, development, and production 

activities. All plans for OCS oil- and gas-related activities (e.g., exploration and development plans, 

pipeline applications, geological and geophysical activities, and structure-removal applications) go 

through rigorous BOEM review and approval to ensure compliance with established laws and 

regulations. Existing mitigating measures must be incorporated and documented in plans submitted 

to BOEM. Operational compliance of the mitigating measures is enforced through the Bureau of 

Safety and Environmental Enforcement’s (BSEE’s) onsite inspection program.

Mitigating measures are an integral part of BOEM’s program to ensure that postlease 

operations are always conducted in an environmentally sound manner (with an emphasis on 

minimizing any adverse impact of routine operations on the environment). For example, post-activity 

surveys are carried out to ensure that a site has been cleared of potential snags to commercial 

fishing gear, and pre-activity surveys seek to avoid archaeological sites and biologically sensitive 

areas such as pinnacles, topographic features, and chemosynthetic communities.

Some BOEM-identified mitigating measures are incorporated into OCS operations through 

cooperative agreements or efforts with industry and State and Federal agencies. These mitigating 

measures include the National Marine Fisheries Service’s (NMFS’s) Observer Program to protect 

marine mammals and sea turtles during explosive removals, labeling operational supplies to track 

possible sources of debris or equipment loss, development of methods of pipeline landfall to 

eliminate impacts to beaches or wetlands, and beach cleanup events.

Site-specific mitigating measures are also applied by BOEM during plan and permit reviews. 

BOEM realized that many of these site-specific mitigations were recurring and developed a list of 

“standard” or commonly applied mitigations. There are currently over 120 standard mitigations. The 

wording of a standard mitigation is developed by BOEM in advance and may be applied whenever 

conditions warrant. Standard mitigation text is revised as often as is necessary (e.g., to reflect 

changes in regulatory citations, agency/personnel contact numbers, and internal policy). Sitespecific mitigation “categories” include the following: air quality; archaeological resources; artificial 

reef material; chemosynthetic communities; Flower Garden Banks; topographic features; hard 

bottoms/pinnacles; military warning areas and Eglin Water Test Areas (EWTAs); hydrogen sulfide 

(H2S); drilling hazards; remotely operated vehicle surveys; geophysical survey reviews; and general

safety concerns. Site-specific mitigation “types” include the following: advisories; conditions of 

approval; hazard survey reviews; inspection requirements; notifications; post-approval submittals; 

and safety precautions. In addition to standard mitigations, BOEM may also apply nonrecurring 

mitigating measures that are developed on a case-by-case basis.
B-4 Gulf of Mexico Multisale EIS

Following a lease sale, an applicant seeks approvals to develop their lease by preparing and 

submitting OCS plans. The OCS plans are reviewed by BOEM and, depending on what is proposed 

to take place in a specific place, BOEM may assign conditions of approval (COA). The COAs 

become part of the approved postlease authorization and include environmental protections, 

requirements that maintain conformance with law, the requirements of other agencies having 

jurisdiction, or safety precautions.

Some of BOEM’s conditions of approval include the following:

• other approvals prerequisite to BOEM’s approval (e.g., the Coastal Zone 

Management Act);

• safety precautions (e.g., H2S present);

• post-approval submittals (e.g., surveys and interpretive reports);

• inspection requirements (e.g., pipeline pressure testing);

• pre-deployment notifications (e.g., U.S. Department of Defense use restrictions 

and Military Warning Areas); and

• reduce or avoid environmental impacts on resources identified in NEPA or other 

laws (e.g., the National Historic Preservation Act).

BOEM is continually revising applicable mitigations to allow the Gulf of Mexico OCS Region 

to more easily and routinely track mitigation compliance and effectiveness. A primary focus of this 

effort is requiring post-approval submittal of information within a specified timeframe or after a 

triggering event (e.g., end of operations reports for plans, construction reports for pipelines, and 

removal reports for structure removals).

Table B-1 provides a list and description of standard postlease mitigating measures that may 

be required by BOEM or BSEE as a result of plan and permit review processes for the Gulf of 

Mexico OCS Region.
Commonly Applied Mitigating Measures

B-5

Table B-1. Commonly Applied or “Standard” Mitigating Measures.

Mitigation 

Number Mitigating Measure Title Description of Mitigation

0.0 Non-Recurring Mitigation A non-recurring mitigation is a mitigating measure that is used for a unique, special, onetime-only mitigation that is added to certain plans.

Boat Traffic Mitigations

1.04 Seismic Vessels (protected 

species requirements)

The applicant will comply with Notice to Lessees and Operators (NTL) 2012-JOINT-G02, 

“Implementation of Seismic Survey Mitigation Measures and Protected Species Observer 

Program.” Additionally, the applicant will comply with the guidance under this NTL when 

operating in all water depths (not just in water depths >200 m [656 ft] or in the Eastern 

Planning Area), and the NTL’s “Shut-Down Conditions” will be applied towards manatees.

1.05 Seismic Vessels (vessel-strike 

avoidance/reporting)

The applicant will follow the guidance provided under NTL 2012-JOINT-G01, “Vessel 

Strike Avoidance and Injured/Dead Protected Species Reporting.” This provides guidance 

on how a seismic applicant should implement monitoring programs to minimize the risk of 

vessel strikes to protected species and report observations of injured or dead protected 

species. In lieu of a formal observer program, NTL 2012-JOINT-G01 provides specific 

guidelines that should be followed to identify and avoid injury to marine mammals and sea 

turtles.

1.06 Progressive-Transport/“Hopping” 

(structure removals)

In accordance with the Outer Continental Shelf Lands Act (OCSLA) requirements (30 CFR 

§ 250.1727(g)), if at any point in the decommissioning schedule progressivetransport/“hopping” activities are required to section the jacket assembly or support 

material barge loading, a prior written request must be submitted and approval must be 

obtained from the Bureau of Safety and Environmental Enforcement’s (BSEE’s) Regional 

Supervisor, Field Operations. The applicant’s request to use progressive-transport must 

include a detailed procedural narrative and separate location plat for each “set-down” site, 

showing pipelines, anchor patterns for the derrick barge, and any known archaeological 

and/or potentially sensitive biological features. The diagram/map of the route to be taken 

from the initial structure location along the transport path to each site must also be 

submitted with the request. If the block(s) that the applicant intends to use as “set-down” 

sites have not been surveyed as per NTL 2009-G39, “Biologically-Sensitive Underwater 

Features and Areas,” and NTL 2005-G07, “Archaeological Resource Surveys and 

Reports,” the applicant may be required to conduct the necessary surveys/reporting prior 

to mobilizing on site and conducting any seafloor-disturbing activities.
B-6 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

1.07 Seismic Vessels (notification 

requirements)

In accordance with 30 CFR § 550.208(b)(2), the applicant is hereby required to notify other 

users of the Outer Continental Shelf (OCS) before conducting the proposed ancillary 

activities. Prior to commencing the survey(s), the applicant must inform the operators of 

all leases affected by the proposed activities of when and where the applicant intends to 

conduct the vessel operations to ensure that proper navigation and safety protocol are 

observed.

Air Quality Mitigations

2.05 Fuel Usage or Run Time 

Documentation

The projected nitrogen oxides (NOx) emissions amounts in the plan were calculated using 

historic (insert fuel consumption rates, run times). Maintain monthly records of the total 

annual (insert fuel consumption, run times) for the (specify the affected vessels or 

equipment) with a limit of (insert limit in gallons/year, limit in hours/year) and provide the 

information to the Bureau of Ocean Energy Management’s (BOEM’s) Regional Supervisor, 

Office of Leasing and Plans, Plans Section annually by February 1st of each year, 

beginning in the year (insert year). If no activities were conducted during a calendar year, 

provide a statement to that effect in lieu of the required records. If at any time during the 

applicant’s activities these records indicate that the NOx annual emissions may exceed the 

annual limit approved in your plan or the total annual (insert fuel consumption, run time) 

limit, the applicant must immediately prepare a revised plan pursuant to 30 CFR § 550.283 

to include the recalculated emissions amounts. The applicant will not proceed with the 

actions that could cause the potential annual increase in emissions until the revised plan 

has been submitted to and approved by BOEM.

2.08 Potential to Exceed SO2

Significance Levels (flaring)

Should hydrogen sulfide (H2S) concentrations greater than (insert number) ppm be 

encountered, the 3- and 24-hour sulphur oxides (SO2) onshore ambient air concentration 

significance levels as prescribed by 30 CFR § 550.303(e) could be exceeded during the 

proposed well test flaring. Therefore, the applicant is advised that, should H2S 

concentrations greater than (insert number) ppm be encountered, they shall use the graph 

included in their plan to determine the maximum allowable flow rate for the flaring 

operation. The applicant is responsible for ensuring that their maximum emission 

concentrations remain below the aforementioned significance levels. In accordance with 

30 CFR § 250.1164(c), the applicant is hereby required to submit monthly reports that 

contain the following: (1) the daily volume and duration (number of hours) of each flaring 

episode; (2) the H2S concentration (ppm) in the flared gas; and (3) the calculated amount 

of SO2 emitted.
Commonly Applied Mitigating Measures

B-7

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

2.11 Using Ultra-Low Sulfur Content 

Fuel

As proposed, use ultra-low sulfur content diesel fuel (sulfur concentration 0.0015% or less 

by weight) while conducting these operations. Sulfur content records must be maintained 

on the platform and made available to authorized BSEE personnel upon request.

2.12 Verification of Emissions Factors 

(clean burn engines)

The rating, manufacturer, and type of engine(s) proposed in the applicant’s plan will be 

operated and maintained in accordance with the manufacturer’s specifications. Using a 

U.S. Environmental Protection Agency (USEPA)-approved or equivalent method, perform 

an emissions stack test on the subject engine(s) within 60 days following installation and 

at least every 3 years thereafter. These tests will be performed at loads representing 25, 

50, 75, and 100 percent of the rated capacity or at minimum, average, and highest 

operational loads to verify that the emission factors are not exceeding those used in 

calculating the proposed emissions in the plan.

Prepare a report of the results of each stack test and submit it to BOEM’s Regional 

Supervisor, Office of Leasing and Plans, Plans Section within 45 days of the test. During 

engine operation, the applicant will maintain the baseline parameters (such as air-fuel 

rations) established during the most recent successful stack test. The applicant must 

monitor and record these parameters daily to ensure consistency with those observed 

during the most recent successful stack test. Records of these parameters must be 

maintained on the platform and made available to authorized BSEE personnel upon 

request. In addition, the applicant must submit this information to BOEM’s Regional 

Supervisor, Office of Leasing and Plans, Plans Section annually by February 1st of each 

year, beginning in the year (insert year). If no activities were conducted during a calendar 

year, provide a statement to that effect in lieu of the required records.

2.13 Monitoring of NOx Emissions 

(catalytic converters)

The rating, manufacturer, and type, and catalytic converter(s) proposed in the plan must 

be operated and maintained in accordance with the manufacturer’s specifications. Using a 

USEPA-approved or equivalent method, perform an emissions stack test on the subject 

engine(s) and catalytic converter(s) within 60 days following installation and at least every 

3 years thereafter. These tests will be performed at loads representing 25, 50, 75, and 

100 percent of the rated capacity or at minimum, average, and highest operational loads to 

verify that the emissions factors are not exceeding those used in calculating the proposed 

emissions in the plan. The applicant must contact BSEE at least 30 days prior to 

conducting the test to determine proper protocol for the stack test and also to have 

BSEE’s representative witness the test. Prepare a report of the results of each stack test 

and submit it to BOEM’s Regional Supervisor, Office of Leasing and Plans, Plans Section 

within 45 days of the test.
B-8 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

During operation, the applicant will maintain the baseline parameters, such as air-fuel 

ratios for the engine(s) and the pressure drop and temperature increase across the 

catalytic converter(s) established during the most recent successful stack test. The 

applicant must monitor and record these parameters daily to ensure they remain 

consistent with those observed during the most recent successful stack test. The records 

of these parameters will be maintained on the platform and made available to authorized 

BSEE personnel upon request. In addition, the applicant must submit this information to 

BOEM’s Regional Supervisor, Office of Leasing and Plans, Plans Section annually by 

February 1st of each year, beginning in the year (insert year). If no activities were 

conducted during a calendar year, the applicant must provide a statement to that effect in 

lieu of the required records.

2.15 Sulfur Recovery Unit, Flaring 

Episodes, Production 

Curtailment

If a shutdown of the sulfur recovery unit necessitates diverting the acid gas stream and if 

the resulting increased emissions would cause the SO2 onshore ambient air concentration 

significance levels as prescribed by 30 CFR § 550.303(e) to be exceeded, begin curtailing 

production within 6 hours of the onset of the increased emissions. If curtailment is 

necessary, the appropriate reduced production rate will be reached no later than 8 hours 

from the onset of the increased emissions and will continue until such time that normal 

operation of the sulfur recovery unit can resume.

2.16 Monitoring of SO2 Emissions 

(sulfur recovery units)

The amine unit and the (specify name of sulfur recovery unit) proposed in the plan must be 

operated and maintained in accordance with the manufacturer’s specifications. Using a 

USEPA-approved or equivalent method, perform an emissions stack test on the subject 

sulfur recovery unit within 60 days following installation. This test will be performed at 

loads representing 25, 50, 75, and 100 percent of the rated capacity of the amine unit or at 

minimum, average, and highest operational loads of the amine unit to verify that the 

emission factors are not exceeding those used in calculating the proposed emissions in 

the plan. Contact BSEE’s Environmental Enforcement Division at least 30 days prior to 

conducting the test to determine proper protocol for the stack test and also to have 

BSEE’s representative witness the test. Prepare a report of the results of each stack test 

and submit it to BOEM’s Regional Supervisor, Office of Leasing and Plans, Plans Section 

within 45 days of the test.

The applicant must monitor and record these parameters daily to ensure they remain 

consistent with the approved baseline parameters from the most recent successful stack 

test. Records of these parameters must be maintained on the platform and made 

available to authorized BSEE personnel upon request. In addition, the applicant must 
Commonly Applied Mitigating Measures

B-9

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

submit this information to BOEM’s Regional Supervisor, Office of Leasing and Plans, 

Plans Section annually by February 1st of each year, beginning in the year (insert year). If 

no activities were conducted during a calendar year, provide a statement to that effect in 

lieu of the required records.

2.17 Verification of Emissions Factors 

(general)

The rating, manufacturer, and type of engine(s) proposed in the plan will be operated and 

maintained in accordance with the manufacturer’s specifications. Using a USEPAapproved or equivalent method, perform an emissions stack test on the subject engine(s) 

within 60 days following installation and at least every 3 years thereafter. These tests will 

be performed at loads representing 25, 50, 75, and 100 percent of the rated capacity or at 

minimum, average, and highest operational loads to verify that the emission factors are 

not exceeding those used in calculating the proposed emissions in the plan. Contact 

BSEE’s Environmental Enforcement Division at least 30 days prior to conducting the test 

to determine proper protocol for the stack test and also to have the BSEE representative 

witness the test.

Prepare a report of the results of each stack test and submit it to BOEM’s Regional 

Supervisor, Office of Leasing and Plans, Plans Section within 45 days of the test. During 

engine operation, the applicant will maintain the baseline parameters (such as air-fuel 

rations) established during the most recent successful stack test. The applicant must 

monitor and record these parameters daily to ensure consistency with those observed 

during the most recent successful stack test. Records of these parameters must be 

maintained on the platform and made available to authorized BSEE personnel upon 

request. In addition, the applicant must submit this information to BOEM’s Regional 

Supervisor, Office of Leasing and Plans, Plans Section annually by February 1st of each 

year, beginning in the year (insert year). If no activities were conducted during a calendar 

year, provide a statement to that effect in lieu of the required records.

2.18 Alternative Monitoring of NOx

Emissions (catalytic converters)

Using your established baseline parameters listed below, monitor the performance of the 

engine(s) and catalytic converter(s) and record daily to ensure that performance remains 

consistent. Air to fuel ratio for engine: (insert baseline parameters); pressure drop across 

catalytic converter: (insert baseline parameters); and temperature increase across 

catalytic converter: (insert baseline parameters).

Records of these parameters must be maintained on the platform and made available to 

authorized BSEE personnel upon request. In addition, the applicant must submit a 

summary of these data to BOEM’s Regional Supervisor, Office of Leasing and Plans, 
B-10 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

Plans Section annually by February 1st of each year, beginning in the year (insert year). 

The summary will report minimum, average, and maximum values for the above-listed 

parameters, on a monthly basis, for the year. If no activities were conducted during a 

calendar year, provide a statement to that effect in lieu of the required records. Notify 

BOEM’s Regional Supervisor, Office of Leasing and Plans, Plans Section as soon as 

practical but no later than 24 hours after the event, whenever the engine(s) or catalytic 

converter(s) exceed these parameters for periods greater than a day. File a detailed 

report with this office within 5 days of the termination of any such event. At a minimum, 

this report will include a chronology of the event, NOx emissions rates in pounds per hour, 

total NOx emissions for the duration of the event, and any measures taken to regain 

operation within these parameters or to prevent a recurrence of similar events. If 

exceeding the above parameters results in increased emissions that would cause onshore 

NOx concentration to exceed BOEM significance levels (30 CFR § 550.303(e)), curtail the 

use of the (identify equipment associated with catalytic converter) within 2 days of the 

onset of the increased emissions and continue curtailment until such time that normal 

operation of the catalytic converter can resume.

Archaeology Mitigations

3.00 Archaeology Non-Recurring 

Mitigation

A non-recurring mitigation is a mitigating measure that is used for a unique, special, onetime-only mitigation that is added to certain plans.

3.02 Buried Channels (pipeline 

applications)

BOEM’s review indicates that the proposed activities are in the vicinity of buried channel 

margin features that may contain significant archaeological resources. In accordance with 

30 CFR § 250.1007(a)(5), the applicant must either (1) conduct an underwater 

archaeological investigation (diver and/or remotely operated vehicle (ROV) investigations) 

prior to commencing activities to determine whether these features represent 

archaeological resources or (2) ensure that the depth of the pipeline trench in the vicinity 

of these features does not exceed 3 ft and that all other seafloor-disturbing actions 

resulting from the proposed activities avoid the subject channel margins (see the enclosed 

map depicting the avoidance area in the application). If the applicant conducts an 

underwater archaeological investigation prior to commencing operations, the applicant 

should contact BOEMs’ Office of Environment and BSEE’s Environmental Enforcement 

Branch at least 2 weeks prior to performing operations to obtain the investigation 

methodology. If the applicant chooses to avoid the features, then the applicant should 

submit anchor position plats, at a scale of 1 in = 1,000 ft with differential global positioning 

system (DGPS) accuracy, with your pipeline construction report required by 30 CFR § 

250.1008(b). These plats must depict the “as-placed” location of all anchors, anchor 
Commonly Applied Mitigating Measures

B-11

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

chains, wire ropes, and cables on the seafloor (including sweep) and demonstrate that the 

features were not physically impacted by the construction activities. If the applicant 

chooses to avoid the features and no anchoring activities were conducted during pipeline 

construction, provide a statement to that effect in lieu of the required anchor position plats. 

This mitigation may be applied by BSEE at the post-approval stage.

3.03 Buried Channels (plans) BOEM’s review indicates that the proposed activities are in the vicinity of buried channel 

margin features that may contain significant archaeological resources. In accordance with 

30 CFR § 550.194, the applicant must either (1) conduct an underwater archaeological 

investigation (diver and/or ROV investigations) prior to commencing activities to determine 

whether these features represent archaeological resources or (2) ensure that all seafloordisturbing actions resulting from the proposed activities avoid the subject features (see the 

enclosed map depicting the avoidance area in the application). If the applicant conducts 

an underwater archaeological investigation prior to commencing operations, contact 

BOEM’s Office of Environment least 2 weeks prior to performing operations to obtain the 

investigation methodology.

If the applicant chooses to avoid the features, then submit an as-built map at a scale of 

1 in = 1,000 ft with DGPS accuracy, showing the location of all seafloor disturbances (e.g., 

the rig or platform, anchors, anchor chains, wire ropes, cables, etc.) relative to these 

features, to BOEM’s Regional Supervisor, Office of Leasing and Plans, Plans Section at 

the same time that the applicant submits its (specify submittal type).

3.04 and 

3.05

Magnetic Anomalies and/or 

Side-Scan Sonar Targets 

(pipeline applications - multiple 

features)

Magnetic Anomalies and/or 

Side-Scan Sonar Targets 

(pipeline application – singular 

feature)

BOEM’s review indicates that the proposed activities are in the vicinity of the unidentified 

(insert magnetic anomalies, side-scan sonar targets, magnetic anomalies and side-scan 

sonar targets) listed in the enclosure, features that may represent significant 

archaeological resources. In accordance with 30 CFR § 250.1007(a)(5), the applicant 

must either (1) conduct an underwater archaeological investigation (diver and/or ROV 

investigations) prior to commencing activities to determine whether these features 

represent archaeological resources or (2) ensure that all seafloor-disturbing actions 

resulting from the proposed activities avoid the unidentified features by a distance greater 

than that listed in the enclosure. If the applicant conducts an underwater archaeological 

investigation prior to commencing operations, then the applicant must contact BOEM’s 

Office of Environment at least 2 weeks prior to performing operations to obtain the 

investigation methodology. If the applicant chooses to avoid the features, then submit 

anchor position plats, at a scale of 1 in = 1,000 ft with DGPS accuracy, with the pipeline 

construction report required by 30 CFR § 250.1008(b). These plats must depict the “as-
B-12 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

placed” location of all anchors, anchor chains, wire ropes, and cables on the seafloor 

(including sweep) and demonstrate that the features were not physically impacted by the 

construction activities. If the applicant chooses to avoid the features and no anchoring 

activities were conducted during pipeline construction, then provide a statement to that 

effect in lieu of the required anchor position plats. This mitigation may be applied by 

BSEE at the post-approval stage.

3.06 and 

3.07

Magnetic Anomalies and/or 

Side-Scan Sonar Targets (plans 

– multiple features)

Magnetic Anomalies and/or 

Side-Scan Sonar Targets (plans 

– singular feature)

BOEM’s review indicates that the proposed activities are in the vicinity of the unidentified 

(insert magnetic anomalies, side-scan sonar targets, magnetic anomalies and side-scan 

sonar targets) listed in the enclosure of the application, features that may represent 

significant archaeological resources. In accordance with 30 CFR § 550.194, the applicant 

must either (1) conduct an underwater archaeological investigation (diver and/or ROV 

investigations) prior to commencing the activities to determine whether these features 

represent archaeological resources or (2) ensure that all seafloor-disturbing actions 

resulting from the proposed activities avoid the subject features by a distance greater than 

that listed in the enclosure of the application. If the applicant conducts an underwater 

archaeological investigation, then the applicant must contact BOEM’s Office of 

Environment at least 2 weeks prior to performing operations to obtain the investigation 

methodology. If the applicant chooses to avoid the features, submit an as-built map at a 

scale of 1 in = 1,000 ft with DGPS accuracy, showing the location of all seafloor 

disturbances (e.g., the rig or platform, anchors, anchor chains, wire ropes, cables, etc.) 

relative to these features to BOEM’s Regional Supervisor, Office of Leasing and Plans, 

Plans Section at the same time the applicant submits the plan.

3.08 Buried Channels (lease block 

survey review

BOEM’s review of the archaeological assessment indicates that there are buried channel 

margin features that may contain significant archaeological resources in the lease 

block(s). The enclosed map in the application identifies the areas to be avoided during 

any future development within the block(s). In accordance with 30 CFR § 550.194, the 

applicant must either (1) conduct an underwater archeological investigation (diver and/or 

ROV investigations) to determine whether these features represent archaeological 

resources or (2) ensure that all seafloor-disturbing actions required by future exploration or 

development will avoid the subject features. If the applicant chooses to conduct an 

underwater archaeological investigation, then the applicant must contact BOEM’s Office of 

Environment at least 2 weeks prior to performing operations to obtain the investigation 

methodology.
Commonly Applied Mitigating Measures

B-13

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

3.09 and 

3.10

Magnetic Anomaly and/or SideScan Sonar Target (survey 

review – single feature)

Magnetic Anomaly and/or SideScan Sonar Target (survey 

review – multiple features)

BOEM’s review of the archaeological assessment indicates the presence of the 

unidentified magnetic anomaly(ies), side-scan sonar target(s), or magnetic anomaly(ies) 

and side-scan sonar target(s) listed in the enclosure of the application, features that may 

represent significant archaeological resources. In accordance with 30 CFR § 550.194, the 

applicant must either (1) conduct an underwater archaeological investigation (diver and/or 

ROV investigations) to determine whether these features represent archaeological 

resources or (2) ensure that all seafloor-disturbing actions required by future exploration 

and development avoid the unidentified features by a distance greater than that listed in 

the enclosure of the application. If the applicant conducts an underwater archaeological 

investigation, then the applicant must contact BOEM’s Office of Environment at least 

2 weeks prior to performing operations to obtain the investigation methodology.

3.11 Unsurveyed Area (plans) Avoid impacts to the seafloor in the unsurveyed area approximately (insert number) feet to 

the (insert direction) of the proposed (specify Well X, Wells X and Y, Platform X, etc.). 

This area has been identified as requiring a (insert 50-meter or 300-meter) line spacing 

archaeological resource survey to determine the potential for archaeological resources. 

BOEM has no archaeological resource assessment on file for this area and, therefore, 

cannot determine the potential effects to archaeological resources outside of the 

applicant’s survey coverage. Submit an as-built map at a scale of 1 in = 1,000 ft with 

DGPS accuracy, showing the location of all seafloor disturbances (e.g., the rig or platform, 

anchors, anchor chains, wire ropes, cables, etc.) relative to the unsurveyed area to 

BOEM’s Regional Supervisor, Office of Leasing and Plans, Plans Section at the same time 

the applicant submits the plan.

3.12 and 

3.13

Magnetic Anomalies and/or 

Side-Scan Sonar Targets 

(structure removals – multiple 

features)

Magnetic Anomalies and/or 

Side-Scan Sonar Targets 

(structure removals – single 

feature)

BOEM’s review indicates that the proposed activities are in the vicinity of the unidentified 

magnetic anomaly(ies), side-scan sonar target(s), or magnetic anomaly(ies) and side-scan 

sonar target(s) listed in the table in the application, a feature that may represent a 

significant archaeological resource. In accordance with 30 CFR § 250.194(c), the 

applicant must either (1) conduct an underwater archaeological investigation (diver and/or 

ROV investigations) prior to commencing activities to determine whether this feature 

represents an archaeological resource or (2) ensure that all anchoring operations (e.g., 

anchors, anchor chains, wire ropes, cables, etc.) avoid the unidentified feature by a 

distance greater than that listed in the table in the application. If the applicant plans to 

conduct an underwater archaeological investigation prior to commencing operations, then 

the applicant must contact BOEM’s Office of Environment to obtain the investigation 

methodology at least 2 weeks prior to performing operations and contact BOEM’s Office of 

Environment and BSEE’s Environmental Enforcement Branch. If the applicant chooses to 
B-14 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

avoid the feature, then include in the post-removal report as-built plats, at a scale of 1 in = 

1,000 ft with DGPS accuracy, the position of anchors, anchor chains, wire ropes, and 

cables deployed during the structure removal relative to the feature. In addition, supply a

copy of ALL vessel logs related to the removal operations (e.g., anchor handling vessels, 

lift boats, dive vessels, and tug boats). This mitigation may be applied by BSEE at the 

post-approval stage.

3.16 ROV Surveys (plans) The proposed operations are in an area designated by BOEM’s Regional Director as 

having a high potential for the location of historic shipwrecks. In accordance with 30 CFR 

§ 550.194(a)(2), prior to commencing the operations, conduct an ROV investigation (using 

video, sector-scanning sonar, or multibeam bathymetry) of the seafloor areas that could be 

disturbed by the operations (e.g., the rig or platform, anchors, anchor chains, wire ropes, 

cables, etc.) to ensure that the applicant will avoid harming potentially significant 

archaeological sites. The applicant must contact BOEM’s Office of Environment at least 

2 weeks prior to performing operations to obtain the investigation methodology. The 

applicant must submit a report of this investigation prepared by a qualified marine 

archaeologist, along with an “as-placed” anchor plat and copies of the ROV video and 

acoustic recordings of the investigation to BOEM’s Regional Supervisor, Office of Leasing 

and Plans, Plans Section at the same time the applicant submits the plan. If the applicant 

discovers any potential archaeological resource (i.e., cannot be definitively identified as 

modern debris or refuse) while conducting this investigation or future operations, the 

applicant must immediately halt any seafloor-disturbing activities and report the discovery 

to BOEM’s Regional Supervisor, Office of Environment.

3.17 Conditional Approval for ROV 

Surveys (plans)

Drilling permits will not be issued for proposed well(s) and well name(s) until the applicant 

submits an archaeological report to BOEM’s Regional Supervisor, Office of Leasing and 

Plans, Plans Section and receives approval. This report must be based on an ROV 

investigation (using video, sector-scanning sonar, or multibeam bathymetry) of the 

seafloor areas that could be disturbed by the operations. The report must be prepared by 

a qualified marine archaeologist and must include copies of the ROV video and acoustic 

recordings of the investigation, along with an “as-placed” anchor plat. If the applicant 

discovers any potential archaeological resource (i.e., cannot be definitively identified as 

modern debris or refuse) while conducting this investigation, the applicant must 

immediately halt any seafloor-disturbing activities and report the discovery to BOEM’s 

Regional Supervisor, Office of Environment. The applicant must contact BOEM’s Office of 

Environment at least 2 weeks prior to performing this survey to obtain the investigation 

methodology.
Commonly Applied Mitigating Measures

B-15

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

3.18 Buried Channels (structure 

removal)

BOEM’s review indicates that the proposed activities are in the vicinity of buried channel 

margin features that may contain significant archaeological resources. In accordance with 

30 CFR § 250.194(c), the applicant must either (1) conduct an underwater archaeological 

investigation (diver and/or ROV investigations) prior to commencing activities to determine 

whether these features represent archaeological resources or (2) ensure that all seafloordisturbing actions resulting from the proposed activities (e.g., site-clearance trawling, 

anchors, anchor chains, wire ropes, cables, etc.) avoid the subject features (see the 

enclosed map depicting the avoidance area in the application). If the applicant plans to 

conduct an underwater archaeological investigation prior to commencing operations, then 

the applicant must contact BOEM’s Office of Environment at least 2 weeks prior to 

performing operations to obtain the investigation methodology and contact BOEM’s, Office 

of Environment and BSEE’s Environmental Enforcement Branch. If the applicant chooses 

to avoid the features, then include in the post-removal report as-built plats, at a scale of 

1 in = 1,000 ft with DGPS accuracy, the position of anchors, anchor chains, wire ropes, 

and cables deployed during the structure removal relative to these features. In addition, 

supply a copy of ALL vessel logs related to the removal operations (e.g., anchor handling 

vessels, lift boats, dive vessels, and tug boats). This mitigation may be applied by BSEE 

at the post-approval stage.

3.20 Avoidance of Potential 

Archaeological Resources

BOEM’s review indicates that the proposed operations have the potential to impact 

submerged archaeological resources that could be in the area of potential effect, which 

encompasses all portions of the seafloor where bottom-disturbing activities are to occur. 

Before conducting any authorized, bottom-disturbing activities, the company will follow the 

guidance provided at http://www.boem.gov/Environmental-Stewardship/Archaeology/Gulfof-Mexico-Archaeological-Information.aspx, which includes minimum survey 

recommendations, requisite certification submittals, and post-activity reporting standards 

needed to ensure compliance with the regulations under 30 CFR § 550.194. This 

mitigation may be applied by BSEE at the post-approval stage.

3.21 and 

3.22

Side-Scan Sonar Targets (site 

clearance – single features)

Side-Scan Sonar Targets (site 

clearance – multiple features)

BOEM’s review indicates that the proposed activities are in the vicinity of the unidentified 

side-scan sonar target(s) listed in the table in the application, features that may represent 

significant archaeological resources. In accordance with 30 CFR § 250.194(c), the 

applicant must conduct an underwater archaeological investigation (diver and/or ROV 

investigation) under the supervision of a professional archaeologist to determine whether 

these features represent archaeological resources potentially eligible to the National 

Register of Historic Places prior to conducting site-clearance trawling activities. This 

mitigation may be applied by BSEE at the post-approval stage.
B-16 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

3.23 Protection of Potential 

Archaeological Resources (all 

structure removals)

Per 30 CFR § 250.194(c) and clarified in 2005-G07, if, during site-clearance operations 

the applicant discovers any object of potential archaeological significance, the applicant is 

required to immediately halt operations. In addition, the applicant must immediately report 

this discovery to BSEE’s Environmental Enforcement Branch. Additional guidance will be 

provided to the applicant as to what steps will be needed to protect any potentially 

submerged archaeological resources. In order for BSEE to ensure compliance with 

30 CFR § 250.194(c) and as specified under 30 CFR § 250.1743, the applicant is required 

to provide the trawling logs for both heavy-duty nets and verification nets, with descriptions 

of each item recovered. Should the applicant only pull site-clearance verification nets, the 

applicant must clearly state this within the body of the Site-Clearance Report. The 

applicant is also requested to provide the following as an appendix in the Site-Clearance 

Report: a CD or DVD of all digital photographs of the items recovered during the use of 

both the heavy-duty trawl nets and the site-clearance verification trawl nets. This 

mitigation may be applied by BSEE at the post-approval stage.

Artificial Reef Material Mitigations

4.01 Louisiana (artificial reef area) The proposed anchoring operations are located within 500 ft (152 m) of an artificial reef 

permit area established by the State of Louisiana. At least 2 weeks prior to conducting 

anchoring operations (including the use of anchors, anchor chains, and wire ropes) that 

could disturb the seafloor within 500 ft (152 m) of an artificial reef permit area, the 

applicant must contact the Louisiana Artificial Reef Coordinator to ensure that the 

proposed anchoring operations do not damage reefal material. Prior to conducting 

anchoring operations, the applicant must send an email to BSEE’s Environmental 

Enforcement Branch confirming that the Louisiana Artificial Reef Coordinator has been 

contacted.

If the anchoring operations intersect or cross-over the artificial reef permit area, then 

submit anchor position plats, at a scale of 1 in = 1,000 ft with DGPS accuracy, depicting 

the “as-placed” location of all anchors, anchor chains, wire ropes, and cables (including 

sweep if applicable) on the seafloor relative to the reefal material. For plans, submit the 

plats to BOEM’s Regional Supervisor, Office of Leasing and Plans, Plans Section at the 

same time the applicant submits the End of Operations Report (Form BSEE-0125) to the 

appropriate BSEE, Gulf of Mexico OCS Region, District Office and/or notification of 

platform installation date and final as-built location data as directed in 30 CFR § 

250.900(e). For pipelines, submit the plats with the pipeline construction report required 

by 30 CFR § 250.1008(b). For structure removals, submit the plats with the post-removal 
Commonly Applied Mitigating Measures

B-17

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

report. This mitigation may be applied by BSEE at the post-approval stage.

4.02 Texas (artificial reef general 

permit area)

The proposed operations are located within an artificial reef General Permit Area 

established by the State of Texas. At least 2 weeks prior to conducting operations 

(including the use of anchors, anchor chains, and wire ropes) that could disturb the 

seafloor within the artificial reef General Permit Area, contact the Texas Artificial Reef 

Coordinator to ensure that the proposed operations do not damage reefal material. Prior 

to conducting operations, the applicant must send an email to BSEE’s Environmental 

Enforcement Branch confirming that the Texas Artificial Reef Coordinator has been 

contacted. This mitigation may be applied by BSEE at the post-approval stage.

4.021 Texas (artificial reef permit area 

– anchoring)

The proposed anchoring operations are located within 1,000 ft (305 m) of an artificial reef 

permit area established by the State of Texas. At least 2 weeks prior to conducting 

anchoring operations (including the use of anchors, anchor chains, and wire ropes) that 

could disturb the seafloor within 1,000 ft (305 m) of the artificial reef permit area, contact 

the Texas Artificial Reef Coordinator to ensure that the proposed anchoring operations do 

not damage reefal material. Prior to conducting anchoring operations, the applicant must 

send an email to BSEE’s Environmental Enforcement Branch confirming that the Texas 

Artificial Reef Coordinator has been contacted.

If the anchoring operations intersect or cross-over the artificial reef permit area, submit 

anchor position plats, at a scale of 1 in = 1,000 ft with DGPS accuracy, depicting the 

“as-placed” location of all anchors, anchor chains, wire ropes, and cables (including sweep 

if applicable) on the seafloor relative to the reefal material. For plans, submit the plats to 

BOEM’s Regional Supervisor, Office of Leasing and Plans, Plans Section at the same time 

the applicant submits the End of Operations Report (Form BSEE-0125) to the appropriate 

BSEE, Gulf of Mexico OCS Region, District Office and/or notification of platform 

installation date and final as-built location data as directed in 30 CFR § 250.900(e). For 

pipelines, submit the plats with the pipeline construction report required by 30 CFR § 

250.1008(b). For structure removals, submit the plats with the post-removal report. This 

mitigation may be applied by BSEE at the post-approval stage.

4.03 Mississippi (artificial reef area) The proposed anchoring operations are located within 500 ft (152 m) of an artificial reef 

permit area established by the State of Mississippi. At least 2 weeks prior to conducting 

anchoring operations (including the use of anchors, anchor chains, and wire ropes) that 

could disturb the seafloor within 500 ft (152 m) of an artificial reef structure or an artificial 

reef permit area, contact the Mississippi Artificial Reef Coordinator to ensure that the 

proposed anchoring operations do not damage reefal material. Prior to conducting 
B-18 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

anchoring operations, the applicant must send an email to BSEE’s Environmental 

Enforcement Branch confirming that the Mississippi Artificial Reef Coordinator has been 

contacted. This mitigation may be applied by BSEE at the post-approval stage.

4.04 Alabama (artificial reef general 

permit area)

The proposed operations are in a General Permit Area established by the State of 

Alabama for the placement of artificial reef material. At least 2 weeks prior to conducting 

operations, contact the Alabama Artificial Reef Coordinator to ensure that the proposed 

operations do not damage reefal material. Prior to conducting operations, the applicant 

must send an email to BSEE’s Environmental Enforcement Branch confirming that the 

Alabama Artificial Reef Coordinator has been contacted. This mitigation may be applied 

by BSEE at the post-approval stage.

4.05 Florida (artificial reef general 

permit area)

The proposed operations are in a General Permit Area established by the State of Florida 

for the placement of artificial reef material. At least 2 weeks prior to conducting 

operations, contact the Florida Artificial Reef Coordinator to ensure that the proposed 

operations do not damage reefal material. Prior to conducting operations, the applicant 

must send an email to BSEE’s Environmental Enforcement Branch confirming that the 

Florida Artificial Reef Coordinator has been contacted. This mitigation may be applied by 

BSEE at the post-approval stage.

4.06 Post-Reefing Survey 

Requirements

BOEM’s review indicates that the structure proposed for decommissioning will be 

abandoned-in-place as an artificial reef under the Rigs-to-Reefs Program. In order to 

verify compliance with OCSLA reefing (30 CFR § 250.1727(g)) and obstruction clearance 

requirements (30 CFR § 250.1740(a)(2)), the applicant is required to conduct a highresolution sonar survey (500 kHz or greater) of the permitted reefal material. The 

applicant must design the line spacing (for side-scan) or sonar drops (for sector-scanning) 

and the display range to ensure that 100 percent of the material permitted under this 

action is covered and that it is demonstrated that the associated seabed is clear of all 

obstructions apart from the reefal material. The applicant is required to submit the sonar 

data/survey report to BSEE’s Environmental Enforcement Branch at the same time as the 

post-removal report. This mitigation may be applied by BSEE at the post-approval stage.

Chemosynthetic Communities Mitigations

5.00 Chemosynthetic Communities 

Non-Recurring Mitigation

A non-recurring mitigation is a mitigating measure that is used for a unique, special, onetime-only mitigation that is added to certain plans.

5.01 Anchor Positioning (GPS) 

(plans)

The proposed activities are in the vicinity of areas that could support high-density 

deepwater benthic communities. Use a state-of-the-art positioning system (e.g., DGPS) 

on the anchor handling vessel to ensure that any seafloor disturbance resulting from the 
Commonly Applied Mitigating Measures

B-19

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

use of anchors (including that caused by the anchors, anchor chains, and wire ropes) does 

not occur within 250 ft (76 m) of such areas (see the enclosed map/Map xxx [specify map 

by name], submitted with the survey report, which depicts the areas). Submit plats for 

Well(s) (insert number[s] or name[s]), which depict the “as-placed” location of all anchors 

and any associated anchor chains and wire ropes on the seafloor, at a scale of 1 in = 

1,000 ft with DGPS accuracy, to BOEM’s Regional Supervisor, Office of Leasing and 

Plans, Plans Section at the same time the applicant submits the End of Operations Report 

(Form BSEE-0125) to the appropriate BSEE, Gulf of Mexico OCS Region, District Office to 

demonstrate that the features were not physically impacted by these anchoring activities. 

This mitigation may be applied by BSEE at the post-approval stage.

5.02 Conventional Pipeline Laying 

Vessels (GPS) (pipeline 

applications)

The proposed pipeline construction activities are in the vicinity of areas that could support 

high-density deepwater benthic communities. Use a state-of-the-art positioning system 

(e.g., DGPS) on the pipeline laying vessel and the anchor handling vessels to ensure that 

any seafloor disturbance (including that caused by anchors, anchor chains, and wire 

ropes) during pipeline construction activities does not occur within 250 ft (76 m) of such 

areas (see the enclosed map/Map xxx [specify map by name], submitted with the pipeline 

application, which depicts the areas). Additionally, include lay barge anchor position plats, 

at a scale of 1 in = 1,000 ft with DGPS accuracy, with the pipeline construction report 

required by 30 CFR § 250.1008(b), which depict the “as-placed” location of all anchors, 

anchor chains, and wire ropes on the seafloor and which demonstrate that the features 

were not physically impacted by the construction activities. This mitigation may be applied 

by BSEE at the post-approval stage.

5.03 Anchor Positioning (ROV) 

(plans)

The proposed activities are in the vicinity of areas that could support high-density 

deepwater benthic communities. Use an ROV to ensure that any seafloor disturbance 

resulting from the use of anchors (including that caused by the anchors, anchor chains, 

and wire ropes) does not occur within 250 ft (76 m) of such areas (see the enclosed 

map/Map xxx [specify map by name], submitted with your survey report which depicts the 

areas). Submit plats for Well(s) (insert number[s] or name[s]), which depict the 

“as-placed” location of all anchors and any associated anchor chains and wire ropes on 

the seafloor, at a scale of 1 in = 1,000 ft with DGPS accuracy, along with the highresolution ROV video on disc or removable drive, to BOEM’s Regional Supervisor, Office 

of Leasing and Plans, Plans Section at the same time the applicant submits the End of 

Operations Report (Form BSEE-0125) to the appropriate BSEE, Gulf of Mexico OCS 

Region, District Office to demonstrate that the features were not physically impacted by 

these anchoring activities. The ROV video screen should show time, date, depth, 
B-20 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

heading, and location coordinates. Observational notes and a corresponding map 

showing the ROV heading shall also be provided. If still images are collected, include the 

same information in the images’ integrated data. This mitigation may be applied by BSEE 

at the post-approval stage.

5.04 Conventional Pipeline Laying 

Vessels (ROV) (pipeline 

applications)

The proposed pipeline construction activities are in the vicinity of areas that could support 

high-density deepwater benthic communities. Use an ROV to ensure that any seafloor 

disturbance (including that caused by the anchors, anchor chains, and wire ropes) during 

pipeline construction activities does not occur within 250 ft of such areas (see the 

enclosed map/Map “xxx” [specify map by name], submitted with the pipeline application, 

which depicts the areas). Submit lay barge anchor position plats, at a scale of 1 in = 

1,000 ft with DGPS accuracy, with the pipeline construction report required by 30 CFR § 

250.1008(b), which depict the “as-placed” location of all anchors, anchor chains, and wire 

ropes on the seafloor and which demonstrate that the features were not physically 

impacted by the construction activities. Additionally, submit the high-resolution ROV video 

on disc or removable drive. The ROV video screen should show time, date, depth, 

heading, and location coordinates. Observational notes and a corresponding map 

showing the ROV heading shall also be provided. If still images are collected, include the 

same information in the images’ integrated data. This mitigation may be applied by BSEE 

at the post-approval stage.

5.05 Dynamically Positioned Pipeline 

Laying Vessels (GPS) (pipeline 

applications)

The proposed pipeline construction activities are in the vicinity of areas that could support 

high-density deepwater benthic communities. Use a state-of-the-art positioning system 

(e.g., DGPS) on the dynamically positioned pipeline laying vessel to ensure that any 

seafloor disturbance resulting from the pipeline construction activities does not occur 

within 250 ft (76 m) of such areas (see the enclosed map/Map “xxx” [specify map by 

name], submitted with the pipeline application, which depicts the areas). Additionally, 

include “as-built” location plats, at a scale of 1 in = 1,000 ft with DGPS accuracy, with the 

pipeline construction report required by 30 CFR § 250.1008(b), which depict the location of 

the pipeline(s) relative to these features to demonstrate that the features were not 

physically impacted by the construction activities. This mitigation may be applied by BSEE 

at the post-approval stage.

5.07 Anchor Positioning (GPS and 

ROV)

The proposed activities are in the vicinity of areas that could support high-density 

deepwater benthic communities. Use a state-of-the-art positioning system (e.g., DGPS) 

on the anchor handling vessel and use an ROV to ensure that any seafloor disturbance 

resulting from the use of anchors (including that caused by the anchors, anchor chains, 

and wire ropes) does not occur within 250 ft (76 m) of such areas. Submit plats for Well(s) 
Commonly Applied Mitigating Measures

B-21

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

(insert number[s] or name[s]), which depict the “as-placed” location of all anchors and any 

associated anchor chains and wire ropes on the seafloor, at a scale of 1 in = 1,000 ft with 

DGPS accuracy, along with the high-resolution ROV video on disc or removable drive, to 

BOEM’s Regional Supervisor, Office of Leasing and Plans, Plans Section at the same time 

the applicant submits the End of Operations Report (Form BSEE-0125) to the appropriate 

BSEE, Gulf of Mexico OCS Region, District Office to demonstrate that the features were 

not physically impacted by these anchoring activities. The ROV video screen should show 

time, date, depth, heading, and location coordinates. Observational notes and a 

corresponding map showing the ROV heading shall also be provided. If still images are 

collected, include the same information in the images’ integrated data. This mitigation 

may be applied by BSEE at the post-approval stage.

5.08 Well Placement Variance (plans) There is an area capable of supporting high-density deepwater benthic communities within 

2,000 ft (610 m) of the proposed well(s), also known as the chemosynthetic well 

parameter. The proposed well(s) is/are (insert chemosynthetic distance parameter) from 

the area capable of supporting high-density deepwater benthic communities, which in this 

case provides adequate protection from muds and cuttings during operations. The actual 

well(s) shall not be placed closer than (CHEMO DISTANCE PARAMETER 1) from the 

potential habitat (see the chemosynthetic map parameter, which depicts the area). 

Provide a map showing the final as-placed well(s), potential habitat, and distance of the 

well(s) from the potential habitat to BOEM’s Regional Supervisor, Office of Leasing and 

Plans, Plans Section at the same time the applicant submits the End of Operations Report 

(Form BSEE-0125) to the appropriate BSEE, Gulf of Mexico OCS Region, District Office to 

demonstrate that the feature(s) were not physically impacted by the drilling activity. This 

mitigation may be applied by BSEE at the post-approval stage.

5.09 Well Placement Variance – “Zero 

Discharge” (plans)

There is an area capable of supporting high-density deepwater benthic communities within 

2,000 ft (610 m) of the proposed well(s) (insert chemosynthetic wells parameter). Since 

this area is (insert chemosynthetic distance parameter) from your well site(s), 

chemosynthetic reason parameter, BSEE permits the activity with the following mitigations 

added.

• Do not move the well(s) any closer to the area capable of supporting highdensity deepwater benthic communities (see chemosynthetic map parameter, 

which depicts the area).

• Follow “zero discharge” practices (i.e., no muds or cuttings shall be 

discharged near the sea surface in the vicinity of the permitted activity).

• In this instance, it is understood that the discharge of muds and cuttings will 
B-22 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

occur on or near the seafloor for the riserless portion of the drilling operations 

ONLY as part of the “zero discharge” practice.

• No muds or cuttings shall be discharged near the seafloor or at the sea 

surface once the blowout preventer and marine riser have been installed. No 

additional or excess muds or cuttings beyond those necessary to properly 

accomplish the riserless portion of the drilling activity shall be discharged on 

or near the seafloor.

• Perform an assessment survey after the drilling of the well(s) is complete. 

(a) Conduct an ROV survey to assess sedimentation and its effects on the 

area capable of supporting high-density deepwater benthic communities (see 

chemosynthetic map parameter 1, which depicts the area. Transects must be 

run no more than 50 ft apart). (b) Ensure that the imagery in the ROV survey 

is high enough quality to adequately assess drilling effects. (This can be 

accomplished by employing the use of high-resolution still photography, highresolution video, and/or lower resolution imaging through the use of close-up 

photography.) (c) The surveyed areas shall be recorded and documented on 

disc or removable drive for review, and the screen should show time, date, 

depth, heading, and location coordinates.

This mitigation may be applied by BSEE at the post-approval stage.

Coastal Zone Management Mitigations

6.01 Texas (Coastal Zone 

Management)

Drilling permits cannot be issued for the proposed wells until concurrence with the coastal 

zone management consistency certification has been received by BOEM’s Office of 

Environment from the Texas General Land Office or until concurrence with the certification 

has been conclusively presumed.

6.02 Louisiana (Coastal Zone 

Management)

Drilling permits cannot be issued for the proposed wells until concurrence with the coastal 

zone management consistency certification has been received by BOEM’s Office of 

Environment from the Louisiana Department of Natural Resources or until concurrence 

with the certification has been conclusively presumed.

6.03 Alabama (Coastal Zone 

Management)

Drilling permits cannot be issued for the proposed wells until concurrence with the coastal 

zone management consistency certification has been received by BOEM’s Office of 

Environment from the Alabama Department of Environmental Management or until 

concurrence with the certification has been conclusively presumed.

6.04 Mississippi (Coastal Zone 

Management)

Drilling permits cannot be issued for the proposed wells until concurrence with the coastal 

zone management consistency certification has been received by BOEM’s Office of 
Commonly Applied Mitigating Measures

B-23

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

Environment from the Mississippi Department of Marine Resources or until concurrence 

with the certification has been conclusively presumed.

6.05 Florida (Coastal Zone 

Management)

Drilling permits cannot be issued for the proposed wells until concurrence with the coastal 

zone management consistency certification has been received by BOEM’s Office of 

Environment from the Florida Department of Environmental Protection or until concurrence 

with the certification has been conclusively presumed.

Flower Garden Banks Mitigations

7.07 Environmental Monitoring Plan Develop a plan for the early initiation of environmental monitoring of the effects of a 

hydrocarbon spill that may occur as a result of the proposed activities on the resources of 

the Flower Garden Banks National Marine Sanctuary, including water quality, pelagic fish, 

and benthic communities.

7.09 Pressure Sensor Testing High- and low-pressure sensors protecting the proposed pipeline will be tested at least 

once bi-weekly with no more than 3 weeks elapsing between each test. The applicant will 

maintain these records on the platform and will make them available to BSEE personnel 

upon request.

7.10 Pressure Sensor Setting The low-pressure sensor protecting the proposed pipeline will be set no lower than 

10 percent below the lower limit of the normal operating pressure range.

Hydrogen Sulfide Mitigations

8.01, 8.02, 

and 8.03

H2S Present (plans)

H2S Unknown (plans)

H2S Absent (plans)

In response to the request accompanying your plan for a hydrogen sulfide (H2S) 

classification, the area in which the proposed drilling operations are to be conducted is 

hereby classified, in accordance with 30 CFR § 250.490(c), as “H2S present,” “H2S 

unknown,” or “H2S absent.”

Accordingly, comply with the appropriate requirements of 30 CFR § 250.490 if H2S is 

present or unknown.

8.04 H2S Concentration Deviation The plan indicates that the applicant anticipates H2S at a concentration of approximately 

(specify the ppm). Should the applicant actually encounter H2S at a concentration greater 

than 500 ppm, revise the plan in accordance with 30 CFR § 550.285 to include toxic 

modeling and an analysis of any potential environmental impacts. Contact BOEM’s Office 

of Environment to obtain the methodology for modeling an H2S plume. The applicant must 

receive approval of the revised plan before additional permits filed under the plan will be 

approved.
B-24 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

8.05 Corrosion Inspections (H2S

pipelines)

Inspect the pipeline(s) bi-annually, annually, or biennially for an indication of corrosion or 

other flaws. Report the results of these inspections to BSEE’s Office of Field Operations 

within 30 days of completion. This mitigation may be applied by BSEE at the postapproval stage.

8.07 National Ocean Service 

Notification (H2S pipelines)

When the applicant provides the National Ocean Service, Nautical Data Section with a 

copy of the pipeline construction report plat, the applicant must also request that the 

National Ocean Service, Nautical Data Section include the pipeline(s) on their navigation 

charts and identify it/them as (an) H2S or toxic sour gas pipeline(s).

8.08 USCG Notification (H2S 

pipelines)

Immediately after the applicant begins operation of the pipeline(s), the applicant must 

notify the U.S. Coast Guard Commander, Eighth Coast Guard District that the pipeline(s) 

is/are in operation and request that the USCG publish information about the pipeline(s), 

including the fact that it is or they are transporting natural gas with a high concentration of 

H2S, in the Eighth District Local Notice to Mariners, Gulf of Mexico.

8.09 H2S Concentration Deviation

(pipeline applications)

The application indicated that the applicant anticipates the H2S concentration of the 

product to be transported in the proposed pipeline is approximately (specify the ppm). 

Should the applicant determine at some future date that the H2S concentration is greater 

than 500 ppm, immediately submit an application to modify the pipeline in accordance with 

30 CFR § 250.1007(b) to include toxic modeling and an analysis of any potential 

environmental impacts. Contact BOEM’s Office of Environment to obtain the methodology 

for modeling an H2S plume.

8.10 Notification to Federal Aviation 

Administration

Prior to initiating operations approved in your plan or pipeline application, the applicant 

shall update their emergency notification list in their H2S contingency plan to include the 

Federal Aviation Administration (FAA): Houston Air Traffic Control/Traffic Management 

Control Desk). In the event of an above-water or below-water sour gas release greater 

than 100 standard cubic feet, notify the FAA that air traffic (except evacuation and medical 

aircraft) should be routed safely away from the site until further notice. For purposes of 

avoidance recommendations to the FAA, a distance of 10 nmi (11.5 mi; 18.5 km) and an 

altitude of 4,000 ft (1,1219 m), as minimal, shall be used. In the case of a release of H2S 

(that constitutes an emergency), notify all facilities that might be exposed to atmospheric 

concentrations of 20 ppm or more of H2S (i.e., all facilities located within [insert number] 

miles of the H2S release). The applicant must also assist in the removal of all personnel 

as well as any other persons observed within the affected area.

8.11 H2S Absent and H2S Present or 

Unknown below Certain Depths 

In response to the request accompanying the plan for a H2S classification, the area in 

which the proposed drilling operations are to be conducted above (specify depth) is hereby 
Commonly Applied Mitigating Measures

B-25

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

(plans) classified, in accordance with 30 CFR § 250.490(c), as H2S absent. However, the area in 

which the proposed drilling operations are to be conducted below (specify depth) is hereby 

classified, in accordance with 30 CFR § 250.490(c), as H2S present or unknown. 

Accordingly, comply with the appropriate requirements of 30 CFR § 250.490.

Live Bottom Areas

9.00 Hard Bottoms/Pinnacles/ 

Potentially Sensitive Biological 

Features Non-Recurring 

Mitigation

A non-recurring mitigation is a mitigating measure that is used for a unique, special, onetime-only mitigation that is added to certain plans.

9.01 Hard Bottoms/Pinnacles/ 

Potentially Sensitive Biological 

Features (conventional lay 

barge) (pipeline applications)

BOEM’s analysis indicates that there are hard bottoms/pinnacles/potentially sensitive 

biological features (PSBFs) that likely provide habitat for biological assemblages located 

within the scope of the anchor array of the pipeline lay barge. The pipeline construction 

activities (including the use of anchors, chains, and wire ropes) must avoid these hard 

bottoms/pinnacles/PSBFs as depicted on the enclosed map(s) in the application by a 

distance of at least 100 ft (30 m). Include lay barge anchor position plats, at a scale of 1 in 

= 1,000 ft (305 m) with DGPS accuracy, with the pipeline construction report required by 

30 CFR § 250.1008(b), which depict the “as-placed” location of all anchors, anchor chains, 

and wire ropes on the seafloor and which demonstrate that the features were not 

physically impacted by the construction activities. This mitigation may be applied by BSEE 

at the post-approval stage.

9.03 Hard Bottoms/Pinnacles/ 

Potentially Sensitive Biological 

Features (plans)

BOEM’s analysis indicates that there are hard bottoms/pinnacles/PSBFs located in the 

vicinity of the activities proposed in the plan that likely provide habitat for biological 

assemblages. Any bottom-disturbing activities associated with the activities proposed in 

the plan must avoid these hard bottoms/pinnacles/PSBFs as depicted on the enclosed 

map(s) in the application by a distance of at least 100 ft (30 m). Submit to BSEE’s Office 

of Field Operations at the same time you submit your End of Operations report (Form 

BSEE-0125) to the appropriate BSEE, Gulf of Mexico OCS Region, District Office an asbuilt map at a scale of 1 in = 1,000 ft with DGPS accuracy, showing the location of any 

seafloor disturbance (e.g., jack-up rig, barge anchors, etc.) relative to these features. This 

mitigation may be applied by BSEE at the post-approval stage.

9.04 Hard Bottoms/Pinnacles/ 

Potentially Sensitive Biological 

Features (DP lay barge) 

(pipeline applications)

BOEM’s analysis indicates that there are hard bottoms/pinnacles/PSBFs that likely provide 

habitat for biological assemblages located on or near the proposed pipeline route. The 

pipeline construction activities must avoid these hard bottoms/pinnacles/PSBFs as 

depicted on the enclosed map(s) in the application by a distance of at least 100 ft (30 m). 
B-26 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

This mitigation may be applied by BSEE at the post-approval stage.

9.05 Hard Bottoms/Pinnacles/ 

Potentially Sensitive Biological 

Features (structure removal)

BOEM’s review of the application indicates that there are hard bottoms/pinnacles/PSBFs 

located in the vicinity of the activities proposed in the application that likely provide habitat 

for biological assemblages. Any bottom-disturbing activities associated with the activities 

proposed in the application must avoid these hard bottoms/pinnacles/PSBFs as depicted 

on the enclosed map(s) in the application by a distance of at least 100 ft (30 m). Include in 

the post-removal report the as-built plats, at a scale of 1 in = 1,000 ft with DGPS accuracy, 

which depict the “as-placed” location of all anchors, anchor chains, and wire ropes on the 

seafloor deployed during the structure removal relative to these features. This mitigation 

may be applied by BSEE at the post-approval stage.

9.10 ROV Survey Required NonRecurring MitigationA non-recurring mitigation is a mitigating measure that is used for a unique, special, onetime-only mitigation that is added to certain plans.

Military Mitigations

10.09 Naval Coastal Systems Center Please be reminded that the lease stipulation requires the applicant to enter into an 

agreement with the Coastal Test and Evaluation Division, Coastal System Station/Code 

E21, Panama City, Florida 32407, concerning the control of your electromagnetic 

emissions and use of boats and aircraft in the Naval Coastal Systems Center Area.

11.11 Military Warning Area (all) BOEM’s review indicates that the proposed pipeline route and/or the routes to be taken by 

boats and aircraft in support of the proposed activities are located in or could traverse 

Military Warning Area W-(insert number) or Eglin Water Test Area EWTA-(insert number) 

(see BOEM’s website at http://www.boem.gov/MWA-Boundaries/ for a map of the areas). 

Contact the appropriate individual military command headquarters (see BOEM’s website 

at http://www.boem.gov/Military-Contacts-for-Warning-and-Water-Test-Areas/ for a list of 

the contacts) concerning the control of electromagnetic emissions and the use of boats 

and aircraft in this area(s) before commencing such traffic.

12.01 Unexploded Ordnance The proposed operations are located in an area that was used until 1970 by the U.S. 

Department of Defense as an explosives dumping area. Please be advised that 

precautions should therefore be taken while conducting operations that involve any 

disturbance of the seafloor in order to avoid possible unexploded ordnance.

12.02 Naval Mine Warfare Area

(MU 732, 733, and 734)

The proposed operations are located within a stipulated area designated by the Naval 

Mine Warfare Command for mine operations. Therefore, surface structures for exploration 

activities are subject to approval by BOEM’s Gulf of Mexico OCS Region’s Regional 

Director after consultation with the Commander, Mine Warfare Command. No permanent 

structures or debris of any kind will be allowed in the area during exploration operations. 
Commonly Applied Mitigating Measures

B-27

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

Plans for any above seafloor development operations within the designated area must be 

coordinated with the Commander, Mine Warfare Command, 325 Fifth Street, SE, Corpus 

Christi, Texas 78491-5032.

Shallow Drilling Hazards Mitigations (Plans)

14.01 Shallow Gas and/or Water Flow Exercise caution while drilling due to indications of shallow gas (and/or faulting) (and/or 

possible water flow).

14.02 Seafloor Instability Exercise caution during drilling rig placement due to indications of seafloor instability.

14.03 Insufficient Information Exercise caution during drilling rig placement due to insufficient information regarding 

seafloor foundation integrity.

Shallow Hazards Mitigations

15.01 and 

15.02

Multiple Hazards (plans)

Single Hazard (plans)

BOEM’s review indicates that there are pipeline(s), unidentified magnetic anomaly(ies), 

unidentified side-scan sonar contact(s), or other specified hazard(s) in the vicinity of (insert 

name of platform(s) or well(s)) that may pose a hazard to the proposed operations. 

Therefore, take precautions in accordance with NTL 2008-G05, Section VI.B, prior to 

performing operations.

15.05 and 

15.06

Multiple Hazards 

(plans/pipelines) (anchoring 

activities)

Single Hazard (plans) 

(anchoring)

BOEM’s review indicates that there is a pipeline(s), unidentified magnetic anomaly(ies), 

unidentified side-scan sonar contact(s), or other specified hazard(s) in the vicinity of (insert 

name of platform(s) or well(s)) that may pose a hazard due to anchoring activities 

associated with the proposed operations. If any of these activities will take place within 

150 m (490 ft) of the potential hazard, take precautions in accordance with NTL 2008-G05, 

Section VI.B, prior to performing operations.

15.07 Pipeline Spanning BOEM’s review indicates areas of seafloor relief in the vicinity of the proposed pipeline 

route, which may cause spanning problems for the pipeline. Use an ROV in conjunction 

with the pipeline construction activities to ensure that these areas are avoided to the 

extent possible. Additionally, include a report with the pipeline construction report, which 

is required by 30 CFR § 250.1008(b) and which analyzes the as-laid pipeline with respect 

to spanning and describes the protective measures taken to ensure pipeline integrity for 

those portions of the pipeline where the areas of seafloor relief could not be avoided. This 

mitigation may be applied by BSEE at the post-approval stage.

15.08 Conflict with Anchors Please be advised that exploration activities have been approved or are pending approval 

for (insert lease, block, area), which could potentially interfere with the proposed activities. 

Therefore, the applicant should contact (insert contact name, company, address, phone 

number) prior to commencement of the activities in order to avoid any potential conflicts.
B-28 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

Topographic Features Mitigations

16.00 Topographic Features 

Non-Recurring Mitigation

A non-recurring mitigation is a mitigating measure that is used for a unique, special, onetime-only mitigation that is added to certain plans.

16.01 Shunting All Wells (plans) The proposed activities are within the “4-mile, 3-mile, 1-mile, or 1,000-meter zone” of 

(insert name of topographic feature). Shunt all drill cuttings and drilling fluids to the 

seafloor through a downpipe that terminates an appropriate distance, but no more than 

10 m (33 ft), from the bottom.

16.02 Shunting Some Wells (plans) Some of the proposed activities are within the “4-mile, 3-mile, 1-mile, or 1,000-meter zone” 

of (insert name of topographic feature). For (insert name of wells to be shunted”, shunt all 

drill cuttings and drilling fluids to the seafloor through a downpipe that terminates an 

appropriate distance, but no more than 10 m (33 ft), from the bottom.

16.03 No Activity Zone (right-of-way 

pipeline applications)

BOEM’s analysis indicates that the “no activity zone(s)” of the biologically sensitive 

feature(s) shown on the enclosed map(s) in the application may be located within the 

scope of the anchor array of the pipeline lay barge. Anchors, anchor chains, and wire 

ropes associated with the proposed pipeline construction activities must avoid this/these 

“no activity zone(s)” by a distance of at least 500 ft (152 m). Include lay barge anchor 

positions plats, at a scale of 1 in = 1,000 ft with DGPS accuracy, with the pipeline 

construction report required by 30 CFR § 250.1008(b), which depict the “as-placed” 

location of all anchors, anchor chains, and wire ropes on the seafloor, and which 

demonstrate that the “no activity zone(s)” was/were not physically impacted by the 

construction activities. This mitigation may be applied by BSEE at the post-approval 

stage.

16.04 No Activity Zone (plans) Bottom-disturbing activities associated with the activities proposed in the plan must avoid 

the “no activity zone” of the biologically sensitive feature shown on the enclosed map in 

the application by a distance of at least 500 ft (152 m). Submit to BSEE’s Office of Field 

Operations, at the same time the End of Operations report (Form BSEE-0125) is 

submitted to the appropriate BSEE, Gulf of Mexico OCS Region, District Office, an as-built 

map at a scale of 1 in = 1,000 ft with DGPS accuracy, showing the location of any seafloor 

disturbance (e.g., jack-up rig placement, rig anchors, construction barge anchors, etc.) to 

demonstrate that the “no activity zone(s)” was not physically impacted. This mitigation 

may be applied by BSEE at the post-approval stage.

16.05 No Activity Zone (structure 

removal)

Bottom-disturbing activities associated with the activities proposed in the application must 

avoid the “no activity zone” of the biologically sensitive feature shown on the enclosed 

map in the application by a distance of at least 500 ft (152 m). Include in the post-removal 
Commonly Applied Mitigating Measures

B-29

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

report an as-built plat, at a scale of 1 in = 1,000 ft with DGPS accuracy, depicting the “asplaced” location of all anchors, anchor chains, and wire ropes on the seafloor deployed 

during the structure-removal activities to show that the “no activity zone” was not 

physically impacted. This mitigation may be applied by BSEE at the post-approval stage.

Non-Plan and Pipeline Mitigations

17.02 Fish (structure removals using 

explosives)

Under the Magnuson-Stevens Fisheries Conservation and Management Act, 50 CFR § 

600.725 prohibits the use of explosives to take reef fish in the Exclusive Economic Zone. 

Consequently, those involved in explosive structure removals must not take such stunned 

or killed fish on board their vessels. Should this happen, they could be charged by the 

National Marine Fisheries Service (NMFS) with violation of the Act.

17.04 Site-Clearance Trawling 

Reporting

If trawling is used to comply with the site-clearance verification requirements under 

30 CFR §§ 250.1740-1743, which mandates that turtle excluder devices (TED) be 

removed from the trawl nets to facilitate the collection of seabed debris, the applicant must 

abide by maximum trawl times of 30 minutes, allowing for the removal of any captured sea 

turtles. If, during trawling activities, the applicant captures a sea turtle in the nets, the 

applicant must (1) contact BSEE’s Environmental Enforcement Branch and the NMFS’s 

Southeast Regional Office immediately, (2) resuscitate and release any captured sea 

turtles as per NMFS’s guidelines found online at http://www.sefsc.noaa.gov/turtles/

TM_NMFS_SEFSC_580_2010.pdf (refer to page 3-6, Plate 3-1), and (3) photograph the 

turtle and complete a sea turtle stranding form for each sea turtle caught in the nets. The 

form can be found at http://www.sefsc.noaa.gov/species/turtles/strandings.htm and 

submitted to the NMFS and BSEE.

Conservation Information Document Mitigations

18 Self-Burial Approval BOEM hereby concurs with the determination that the subject pipeline will be installed in 

an area that is prone to self-burial. However, in the future, should it be determined that the 

pipeline(s) constitute(s) a hazard to navigation or commercial fishing operations or unduly 

interferes(s) with other uses of the OCS, the applicant will be required to bury it (them).

18.01 Conservation Information 

Document – Condition of 

Approval

Within 15 days after the proposed well is or wells are completed and logged, submit a 

revision to the plan consisting of the information required for a Conservation Information 

Document in accordance with NTL 2000-N05.

18.02 Conservation Information 

Document – Operations 

Approval

At the applicant’s request, we are approving your development operation coordination 

document (DOCD) prior to the completion of our review of the accompanying 

Conservation Information Document (CID). However, please be advised that, if the CID 

review indicates that any of the proposed activities do not conform to sound conservation, 
B-30 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

engineering, and economic practices as cited in 30 CFR §§ 550.202(a) and 550.1101(a), 

we will, in accordance with 30 CFR § 550.281(4)(b), require such revisions to the DOCD 

as are necessary to make the activities conform to such practices.

ROV Survey Mitigations

19.01 ROV Survey Required –

Exploration Plans (EP)

In accordance with NTL 2008-G06, the applicant must conduct the two ROV surveys 

proposed in the plan. The first survey will be for the first well location approved under this 

plan and which is actually drilled. The post-drilling survey can be conducted at the time 

the applicant is preparing to leave this location. The applicant must submit both survey 

reports within 60 days after the rig leaves the well location. This mitigation may be applied 

by BSEE at the post-approval stage.

19.02 ROV Survey Required – DOCD In accordance with NTL 2008-G06, the applicant must conduct the ROV surveys proposed 

in the plan for the facility location approved under this plan. The applicant must submit the 

pre- and post-installation survey reports within 60 days after the facility installation is 

completed. This mitigation may be applied by BSEE at the post-approval stage.

19.03 ROV Survey Not Required In accordance with NTL 2008-G06, BOEM has determined that the applicant will not need 

to conduct the two ROV surveys proposed in the plan. This mitigation may be applied by 

BSEE at the post-approval stage.

Surveys Mitigations

21.01 Archaeology Assessment Not 

Acceptable

BOEM’s review has determined that the archaeological analysis included in the survey 

report does not meet current BOEM requirements.

21.02 Archaeology Assessment 

Acceptable

BOEM’s review has determined that the archaeological analysis included in the survey 

report meets current BOEM requirements.

21.03 Geophysical Review Acceptable BOEM’s review has determined that the subject survey report complies with the provisions 

of NTL 2008-G05 and, based on available data regarding any manmade hazards that may 

have been present at the time the survey was conducted, contains sufficient information to 

prepare an acceptable shallow hazards analysis for specific drilling or platform sites that 

the applicant may propose in future EPs or DOCDs. However, prior to submitting any 

such EPs or DOCDs, the applicant should update the accompanying anomaly map, if 

appropriate, to indicate the location of any manmade hazards (e.g., pipelines, abandoned 

wells, etc.) that did not exist at the time the survey was performed. Additionally, please be 

reminded that under the guidelines of NTL 2008-G04, the applicant should submit highresolution survey data from the line closest to any proposed well or platform location, with 

one copy of each such EP or DOCD.

21.04 Geophysical Survey Report Not BOEM’s review has also determined the subject survey report does not comply with the 
Commonly Applied Mitigating Measures

B-31

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

Acceptable provisions of NTL 2008-G05.

21.05 3D Survey Waiver Use of three-dimensional (3D) seismic data in lieu of high-resolution survey data as per 

NTL 2008-G05 is acceptable for the requested locations.

Pipeline Section Mitigations and Conditions

22 Concrete Mats The applicant’s request to install protective concrete mats over the pipeline crossings in 

water less than 200 ft (61 m) deep is hereby approved pursuant to 30 CFR § 250.141.

25 Pipeline High-Pressure (PSH) 

Higher Than 15%

The applicant’s request to set the PSH higher than 15 percent above the normal operating 

pressure range is hereby approved pursuant to 30 CFR § 250.142. The pipeline PSH 

shall be set no more than 5 percent above the latest shut-in tubing pressure of the well 

and will not be set above the maximum allowable operating pressure of the pipeline.

26 Denied Self-Burial BOEM cannot concur with the applicant’s determination that the subject pipeline will be 

installed in an area that is prone to self-burial. BOEM will only allow self-burial in areas 

with a soil strength that does not exceed 200 pounds per square foot. Therefore, the 

portions of the pipeline in water depths less than or equal to 200 ft (61 m) shall be buried.

28 Hydrostatic Head to Raise 

Maximum Allowable Operating 

Pressure

The applicant’s request to determine the internal design pressure of the submerged 

portion of the pipeline by considering the effects of the external hydrostatic pressure, in 

lieu of using the standard formula outlined in 30 CFR § 250.1002(a), is hereby approved 

pursuant to 30 CFR § 250.141(a).

National Marine Fisheries Service Mitigations

28.001 Species Protective Measures The applicant must comply with the following species protective measures in all activities 

conducted pursuant to the plan: 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”; and NTL 

2012-BSEE-G01, “Marine Trash and Debris Awareness and Elimination.” These 

measures are designed to promote environmental protection, consistent environmental 

policy, compliance with environmental laws, and safety.

29 Oil Spill Financial Responsibility 

(OSFR) Coverage

BOEM’s review of the application indicates that, per 30 CFR §§ 553.3(1)-(3), the proposed 

right-of-way pipeline is classified as a covered offshore facility (COF) and requires oil-spill 

financial responsibility (OSFR) coverage. At this time, BSEE’s records do not indicate that 

the required OSFR coverage is in place. The applicant is advised that they may begin 

construction of the proposed pipeline immediately. However, in accordance with 30 CFR 

§ 553.15(b), the applicant may not begin operation of the pipeline until they have 

submitted an application showing evidence of OSFR coverage and that demonstration has 

been approved by BSEE.
B-32 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

99 Department of Transportation 

Right-of-Way Pipeline

The applicant shall construct, operate, and maintain the pipeline in accordance with the 

appropriate U.S. Department of Transportation regulations.

110 Spanning Potential There are several fault scarps along with the proposed pipeline route. Include with the 

construction report a listing of the location and length of any pipeline “spanning,” resulting 

from laying the pipeline over these fault scarps. Also include a description of any remedial 

action necessary to minimize “spanning” and prevent pipeline damage. This mitigation 

may be applied by BSEE at the post-approval stage.

Office of Structural Technical Support Mitigations

120.1 Reminder of NTL 2008-G05 If there are pipelines within the immediate proximity of the proposed platform site, 

precautions outlined in NTL 2008-G05, “Shallow Hazards Program,” shall be taken while 

conducting operations.

120.15 Notify National Imagery and 

Mapping

In order to assure publication of onsite activity as it affects marine navigation safety, the 

applicant must notify the National Imagery and Mapping Agency in advance of 

commencement of platform installation.

120.2 Send Report to Office of 

Structural and Technical Support 

(OSTS)

Written notification shall be submitted to the Office of Structural and Technical Support 

(OSTS) and the Pipeline Section within 15 calendar days of completion of the platform 

installation operations, at which time the applicant will be provided with the “Complex 

Identification Number” (CPXID) that has been assigned to this structure. The CPXID 

should be included with other pertinent information (i.e., the right-of-way number, area 

code, block number, platform name, etc.) in all future correspondence related to this 

structure. Should significant problems occur during structure installation operations, 

please inform OSTS immediately. If for any reason the applicant decides not to install this 

structure, they shall submit a written cancellation letter.

120.7 Downhole Well Plugging In accordance with 30 CFR § 250.1710, the applicant must downhole plug and abandon 

all wells on (insert area/block platform name) (except [insert well names]), no later than 

(insert date). However, the applicant will not be required to sever the casings, remove the 

wellhead, or clear the site until the right-of-use expires.

Geological and Geophysical Mitigations (deep-penetration applications)

(no assigned mitigation numbers)

Vessel-Strike Avoidance/Reporting The applicant will follow the guidance provided under NTL 2012-JOINT-G01, “Vessel 

Strike Avoidance and Injured/Dead Protected Species Reporting.” The NTL 2012-JOINTG01 provides guidance on how a seismic operator should implement monitoring programs 

to minimize the risk of vessel strikes to protected species and should report observations 

of injured or dead protected species. In lieu of a formal observer program, this NTL 
Commonly Applied Mitigating Measures

B-33

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

provides specific guidelines that should be followed to identify and avoid injury to marine 

mammals and sea turtles.

Seismic Survey Operation, Monitoring, and 

Reporting Guidelines

The applicant will follow the guidance provided under NTL 2012-JOINT-G02, 

“Implementation of Seismic Survey Mitigation Measures and Protected Species Observer 

Program.” Additionally, the applicant will comply with the guidance under this NTL when 

operating in all water depths (not just in water depths >200 m [656 ft] or in the Eastern 

Planning Area), and the NTL’s “shut-down conditions” will be applied towards manatees.

Pre-Activity Sound-Source and Array 

Calibration Verification

Prior to conducting survey activities, the applicant will verify in writing that the proposed 

airgun arrays to be used are of the lowest sound intensity level that still achieves the 

survey goals. The written verification must include confirmation that the airgun array has 

been calibrated/tuned to maximize subsurface illumination and minimize, to the extent 

practicable, horizontal propagation of noise.

Mandatory Separation Buffer between Survey 

Operations

The applicant will be required to maintain, to the extent it can practicably and safely do so, 

a minimum separation distance of 30 km (19 mi) from any other vessels concurrently 

conducting deep-penetration seismic surveys and 40 km (29 mi) when operating within an 

Area of Concern. To assist in implementation of this measure, BOEM will provide the

applicant with contact information for all deep-penetration seismic applicants concurrently 

permitted/authorized to operate within or near the proposed survey area.

Supplemental Reporting Requirements In addition to the reporting requirements under NTL 2012-JOINT-G02, the applicant is 

required to submit bi-weekly reports containing the information listed below. The reporting 

periods end on the 1st and 15th of each month. These bi-weekly reports are required for 

the total duration of the permit. When applicable, the reports must be submitted with 

survey navigation data for the 2-week reporting period. BOEM has a suggested format for 

the written report. If BOEM’s suggested written format is not used, the following 

information must be submitted along with the navigation data: (1) the dates, locations, and 

duration of any deep-penetration seismic operations conducted during the reporting period 

(the navigation data provides this information); (2) any circumstances that caused the total 

energy output of the airgun source array to exceed that set forth in the permit application; 

(3) confirmation that the permittee maintained, to the extent they could practicably and 

safely do so, the minimum separation distance (If applicable, submit a written explanation 

of why the minimum separation distance was not maintained.); and (4) confirmation that 

the permittee complied with the other terms of Section V of the Settlement Agreement.

Military Warning Area Coordination BOEM’s review indicates that the routes to be taken by boats in support of the applicant’s 

activities traversed Military Warning Areas W-92, W-147AB, and W-602. The applicant 

shall contact the appropriate individual military command headquarters concerning the 
B-34 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

control of electromagnetic emissions and use of boats in each of the areas before 

commencing the operations.

Marine Trash and Debris Awareness and 

Elimination

The applicant will follow the guidance provided under NTL 2012-BSEE-G01, “Marine 

Trash and Debris Awareness and Elimination.” The NTL 2012-BSEE-G01 provides 

information on reducing, if not eliminating, trash intentionally jettisoned into the Gulf of 

Mexico. The programs described in the NTL to assist in the reduction of marine trash and 

debris are the marine trash and debris placards, marine trash and debris awareness 

training, and the marine trash and debris awareness training and certification process.

Geological and Geophysical Mitigation

Natural Resource Defense Council Area of Concern (equal to or greater than 20-m [66-ft] water depth)

(no assigned mitigation numbers)

Seismic Survey Restriction Period BOEM’s review indicates that the proposed survey area falls within a portion of an unusual 

mortality event area declared/established by the National Marine Fisheries Service for 

cetaceans (whales and dolphins). The applicant shall adhere to a restriction period 

between March 1 and April 30 (primary bottlenose dolphin calving season) for deep 

penetration seismic surveys on the Federal OCS in coastal waters out to the 20-m (66-ft) 

isobath in the northern Gulf of Mexico to avoid potential impacts to dolphins in regards to 

behavioral disruptions to mother/calf bonding or masking of important acoustic cues. No 

airgun use, including the use of mitigation guns, is permitted during the restriction period.

Geological and Geophysical Mitigation

Natural Resource Defense Council Area of Concern (equal to or greater than 100-m [328-ft] water depth)

(no assigned mitigation numbers)

Required Passive Acoustic Monitoring (PAM) BOEM requires that the applicant use passive acoustic monitoring (PAM) in water depths 

of 100 m (328 ft) or greater at times of reduced visibility (darkness, rain, fog, etc.) as part 

of their protected species observer program. The PAM will be monitored at all times of 

reduced visibility. Applicants will be required to provide BSEE with a description of the 

passive acoustic system, the software used, and the monitoring plan prior to its use. 

Additionally, after survey completion, the applicant will provide an assessment of the 

usefulness, effectiveness, and problems encountered with the use of PAM for marine 

mammal detection to BSEE for review.

Mitigation for High-Resolution Surveys

Vessel-Strike Avoidance/Reporting The applicant will follow the guidance provided under NTL 2012-JOINT-G01, “Vessel 

Strike Avoidance and Injured/Dead Protected Species Reporting.” The NTL 2012-JOINTG01 provides guidance on how a seismic operator should implement monitoring programs 
Commonly Applied Mitigating Measures

B-35

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

to minimize the risk of vessel strikes to protected species and should report observations 

of injured or dead protected species. In lieu of a formal observer program, this NTL 

provides specific guidelines that should be followed to identify and avoid injury to marine 

mammals and sea turtles.

Marine Trash and Debris Awareness and 

Elimination

The applicant will follow the guidance provided under NTL 2012-BSEE-G01, “Marine 

Trash and Debris Awareness and Elimination.” The NTL 2012-BSEE-G01 provides 

information on reducing, if not eliminating, trash intentionally jettisoned into the Gulf of 

Mexico. The programs described in the NTL to assist in the reduction of marine trash and 

debris are the marine trash and debris placards, marine trash and debris awareness 

training, and the marine trash and debris awareness training and certification process.

Geological and Geophysical Non-Recurring Mitigations

Benthic Communities Review of BOEM’s 3D seismic database of water bottom anomalies identified both 

confirmed deepwater benthic communities and features that could potentially support 

communities within the area of the proposed activities. Based on BOEM’s review of 

exploration activities proposed in the applicant’s application, the following non-recurring 

mitigations are applied to the area encompassed by the plan:

• BOEM’s 3D seismic database of water bottom anomalies and confirmed 

communities shall be used to identify features for the purpose of applying this 

mitigation.

• The following nine water bottom anomaly categories will be considered as 

supporting or potentially supporting deepwater benthic communities, unless 

proved otherwise through high- resolution surveys: anom_conf_coral; 

anom_conf_mvol; anom_conf_orgs; anom_poss_oil_pos; wb_anom_lith; 

wb_anom_mvol; wb_anom_neg; wb_anom_pock; and wb_anom_pos.

• These shape files may be downloaded from http://www.boem.gov/Oil-andGas-Energy-Program/Mapping-and-Data/Map-Gallery/Seismic-Water-BottomAnomalies-Map-Gallery.aspx. 

• Features shall be either avoided or surveyed to confirm the presence or 

absence of deepwater benthic communities.

• Per NTL 2009-G40, “Deepwater Benthic Communities,” a minimum separation 

of 250 ft (76 m) must be maintained between documented communities or 

features that could potentially support high-density deepwater benthic 

communities and bottom-disturbing activities (e.g., sensors deployed on the 

seafloor).
B-36 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

− Therefore, a minimum distance of separation for planned sensor 

deployment sites from any feature or community documented in BOEM’s 

water-bottom anomaly database must be at least 250 ft (76 m).

− If at any time it is determined that a node has landed within 250 ft (76 m) 

of any feature or community documented in BOEM’s water-bottom 

anomaly database, an ROV must be used to document the seafloor 

surrounding the landing location. The seafloor beneath the node and 

arms must be surveyed visually with an ROV for damages. All images

collected during this survey, showing the area within the footprint of the 

node, must be returned to BOEM’s Gulf of Mexico OCS Region, Biological 

Sciences Unit for evaluation.

• As required by NTL 2009-G40, for bottom-disturbing activities occurring within 

500 ft (152 m) of a high-density deepwater benthic community, the operator 

must provide BOEM with an as-placed plat showing the actual location of the 

disturbance on the seafloor, in relation to documented anomalies and 

communities. This requirement will apply to sensors placed within 500 ft 

(152 m) of a documented anomaly or community, as shown in BOEM’s 3D 

seismic database.

For sensor deployments requiring as-placed plats, prepare at a scale of 1 in = 1,000 ft and 

submit to BOEM’s Regional Supervisor, Office of Resource Evaluation, Data Acquisition 

and Special Projects Unit.

Tethered Ocean Bottom Node Surveys Acoustic buoy releases, tethered acoustic pingers, and nodal tethering lines pose an 

entanglement risk to sea turtles and other marine life. Implementing the following 

measures act to reduce the risk of entanglement and ensure proper reporting of 

entanglement situations. Reasonable measures are available to applicants using this 

deployment technique to reduce the risk of entanglement. These measures include the 

following: (1) shortening the acoustic buoy line and tethered acoustic pinger line to the 

shortest length practical; and (2) replacing tether rope lines equal to or greater than 1⁄4-in 

diameter with a thicker, more rigid tether line, modifying the line by tying knots in the line to 

increase the diameter and rigidness in order to minimize the risk of entanglement. 

Additional measures include ensuring that a Protected Species Observer (PSO) is 

onboard each vessel during tethered node retrieval operations. The PSOs will document 

any entanglement of marine species in the nodal gear, specifically noting the location 

where entanglement occurred (e.g., pinger tether, acoustic buoy line, etc.). If a marine 

protected species becomes entangled, specifically a sea turtle, the PSO will immediately 
Commonly Applied Mitigating Measures

B-37

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

begin resuscitation procedures as described in the National Oceanic and Atmospheric 

Administration’s guidelines that can be found at http://www.st.nmfs.noaa.gov/Assets/

Observer-Program/pdf/Shrimp_Reef_fish_Manual_9_22_10.pdf. The PSO must also 

contact the sea turtle stranding network’s State coordinator to report the incident, condition 

of the turtle, and request additional instructions to reduce risk of injury or mortality, 

including rehabilitation and salvage techniques.

Topographic Features The applicant must adhere to the provisions of the topographic features lease stipulation 

and the policy described in NTL 2009-G39, “Biologically-Sensitive Underwater Features 

and Areas,” which restricts any bottom-disturbing activities within 152 m (500 ft) of the 

designated “No Activity Zone” of a topographic feature, as well as all applicable 

requirements described in the NTL.

Potential Archaeological Resource Protection BOEM’s review of the application indicates that numerous targets identified by existing 

remote-sensing data are located in the project area where the ocean bottom cables 

(OBCs) are proposed to be deployed. Therefore, in order to demonstrate compliance with 

30 CFR § 551.6(a)(5), the applicant will either (1) ensure that all seafloor-disturbing 

actions required for the OBC deployment avoid the features by a distance greater than 

that listed in the tables or (2) conduct an underwater archaeological investigation prior to 

cable deployment to determine whether the feature represents an archaeological 

resource. If the applicant chooses to avoid the feature, they will be required to submit a 

plat, at a scale of 1 in = 1000 ft with DGPS accuracy, with their final report as required by 

30 CFR § 551.8(c)(2), which demonstrates the feature was not physically impacted by the 

OBC deployment and retrieval or by any other associated bottom disturbances. If the 

applicant chooses to conduct an underwater archaeological investigation, they will be 

required to comply with the investigation methodology and reporting guidelines found on 

BOEM’s website at http://www.boem.gov/gom-archaeology/. 

This is only a partial list of potential archaeological sites within the project area, based on 

existing remote-sensing data. There are significant portions of the project area within the 

OCS that have received either limited or no previous archaeological survey, and these 

areas are likely to contain additional archaeological materials that may be impacted by the 

proposed operations. If the applicant discovers additional manmade debris that appears 

to indicate the presence of a shipwreck (e.g., a sonar image or visual confirmation of an 

iron, steel, or wooden hull; wooden timbers; anchors; concentrations of manmade objects 

such as bottles or ceramics; and piles of ballast rock) within or adjacent to the proposed 

action area during the proposed survey operations, the applicant will be required to 
B-38 Gulf of Mexico Multisale EIS

Table B-1. Commonly Applied or “Standard” Mitigating Measures. (continued).

Mitigation 

Number Mitigating Measure Title Description of Mitigation

immediately halt operations, take steps to ensure that the site is not disturbed in any way, 

and contact BOEM’s Regional Supervisor, Office of Environment within 48 hours of its 

discovery. The applicant must cease all operations within 1,000 ft (305 m) of the site until 

BOEM’s Regional Director instructs the applicant on what steps must be taken to assess 

the site’s potential historic significance and what steps the applicant must take to protect it. 

If an OBC becomes snagged on any submerged object, divers are required to un-snag 

and retrieve the OBC, and the applicant must submit a report detailing each instance of 

this activity. This report should include the coordinates of the snag (to DGPS accuracy), 

the diver’s description of the submerged object creating the snag, any damage that may 

have resulted from the OBC placement or retrieval operations, and any photographic or 

video imagery that is collected. The applicant must submit a report of any data collected 

as a result of these investigations.
APPENDIX C 

COOPERATING AGENCY 

MEMORANDUM OF AGREEMENT

Cooperating Agency Memorandum of Agreement C-3 

C COOPERATING AGENCY MEMORANDUM OF AGREEMENT
C-4 Gulf of Mexico Multisale EIS
Cooperating Agency Memorandum of Agreement C-5 
C-6 Gulf of Mexico Multisale EIS
APPENDIX D 

PROPOSED PRELEASE MITIGATING MEASURES 

(STIPULATIONS) 

Proposed Prelease Mitigating Measures (Stipulations) D-3 

D PROPOSED PRELEASE MITIGATING MEASURES (STIPULATIONS)

The potential lease stipulations and mitigating measures included for analysis in this 

Multisale EIS were developed as a result of numerous scoping efforts for the continuing OCS 

Program in the Gulf of Mexico. The 10 lease stipulations described below would be considered at 

the prelease stage, as applicable, to any proposed lease sale. These measures will be considered 

for adoption by the Assistant Secretary for Land and Minerals Management (ASLM), under authority 

delegated by the Secretary of the Interior. The analysis of any stipulations for any particular 

alternative does not ensure that the ASLM will make a decision to apply the stipulations to leases 

that may result from any proposed lease sale nor does it preclude minor modifications in wording 

during subsequent steps in the prelease process if comments indicate changes are necessary or if 

conditions change.

Any stipulations or mitigation requirements to be included in a lease sale will be described in 

the Record of Decision for that lease sale. Mitigating measures in the form of lease stipulations are 

added to the lease terms and are therefore enforceable as part of the lease. In addition, each 

exploration and development plan, as well as any pipeline applications that result from a lease sale, 

will undergo a NEPA review, and additional project-specific mitigations applied as conditions of plan 

approval at the postlease stage. The BSEE has the authority to monitor and enforce these 

conditions, and under 30 CFR part 250 Subpart N, may seek remedies and penalties from any 

operator that fails to comply with those conditions, stipulations, and mitigating measures.

D.1 TOPOGRAPHIC FEATURES STIPULATION

As authorized under 40 CFR § 1502.4, the topographic features located in the WPA and 

CPA provide habitat for coral-reef-community organisms (Chapter 4.6.1). There are currently no 

identified topographic features protected under this stipulation in the EPA. Oil- and gas-related 

activities resulting from a proposed action could have a severe, even lethal, impact on or near these 

communities if the Topographic Features Stipulation is not adopted and such activities were not 

otherwise mitigated. The DOI has recognized this problem for some years, and since 1973 

stipulations have been made a part of leases on or near these biotic communities; impacts from 

nearby oil- and gas-related activities were mitigated to the greatest extent possible. This stipulation 

would not prevent the recovery of oil and gas resources but would serve to protect valuable and 

sensitive biological resources.

The Topographic Features Stipulation was formulated based on consultation with various 

Federal agencies and comments solicited from the States, industry, environmental organizations, 

and academic representatives. The stipulation is based on years of scientific information collected 

since the inception of the stipulation. This information includes various Bureau of Land 

Management/MMS (BOEM)-funded studies of topographic highs in the GOM; numerous stipulationimposed, industry-funded monitoring reports; and the National Research Council’s (NRC) report 

entitled Drilling Discharges in the Marine Environment (1983). The blocks affected by the 

Topographic Features Stipulation are shown in Figure 2-4. 
D-4 Gulf of Mexico Multisale EIS

The requirements in the stipulation are based on the following facts:

(1) Shunting of the drilling effluent to the nepheloid layer confines the effluent to a 

level deeper than that of the living components of a high-relief topographic 

feature. Shunting is therefore an effective measure for protecting the biota of 

high-relief topographic features (Bright and Rezak, 1978; Rezak and Bright, 

1981; NRC, 1983).

(2) The biological impact on the benthos from the deposition of nonshunted 

discharge is mostly limited to within 1,000 m (3,281 ft) of the discharge (NRC, 

1983).

(3) The biota of topographic features can be categorized into depth-related zones 

defined by degree of reef-building activity (Rezak and Bright, 1981; Rezak et al., 

1983 and 1985).

The stipulation establishes No Activity Zones at the topographic features. A zone is defined 

by the 85-m (279-ft) bathymetric contour (isobath) because, generally, the biota shallower than 85 m 

(279 ft) are more typical of the Caribbean reef biota, while the biota deeper than 85 m (279 ft) are 

similar to soft bottom organisms found throughout the GOM. Where a bank is in water depths less 

than 85 m (279 ft), the deepest “closing” isobath defines the No Activity Zone for that topographic 

feature. Within the No Activity Zones, no operations, anchoring, or structures are allowed. Outside 

the No Activity Zones, additional restrictive zones are established where oil and gas operations 

could occur, but where drilling discharges would be shunted.

The stipulation requires that all effluents within the area shown as the “1,000-Meter Zone” on 

the Topographic Features Stipulation Map (found on BOEM’s website at http://www.gomr.mms.gov/

homepg/lsesale/topo_features_package.pdf) be shunted to within 10 m (33 ft) of the seafloor. Banks 

containing the more sensitive and productive algal-sponge zone require a shunt zone extending 

1 nmi (1.2 mi; 1.9 km) and an additional 3-nmi (3.5-mi; 5.6-km) shunt zone for development only.

Exceptions to the general stipulation are made for the Flower Garden Banks and the lowrelief banks. Because the East and West features of the Flower Garden Banks have received 

National Marine Sanctuary status, they are protected to a greater degree than the other banks. The 

added provisions at the Flower Garden Banks National Marine Sanctuary (i.e., the boundary as of 

the publication of this Multisale EIS) require that (a) the No Activity Zone be based on the 100-m 

(328-ft) isobath instead of the 85-m (279-ft) isobath and be defined by the “1/4 1/4 1/4” system (a 

method of defining a specific portion of a block) rather than the actual isobath and (b) there be a 

4-Mile Zone instead of a 1-Mile Zone in which shunting is required. Although Stetson Bank (a highrelief feature) was made part of the Flower Garden Banks National Marine Sanctuary in 1996, it has 

not as yet received added protection that would differ from current stipulation requirements.

Low-relief banks have only a No Activity Zone. A shunting requirement would be 

counterproductive because it would put the potentially toxic drilling muds in the same water depth 
Proposed Prelease Mitigating Measures (Stipulations) D-5 

range as the features associated biota that are being protected. Also, the turbidity potentially 

caused by the release of drilling effluents in the upper part of the water column would not affect the 

biota on low-relief features as they appear to be adapted to high turbidity. Claypile Bank, which is a 

low-relief bank that exhibits the Millepora-sponge community, has been given the higher priority 

protection of a 1,000-Meter Zone where monitoring is required.

The stipulation reads as follows:

Topographic Features Stipulation

(a) No activity including placement of structures, drilling rigs, pipelines, or anchoring 

will be allowed within the listed isobath (“No Activity Zone”) of the leases on 

banks as listed below.

(b) Operations within the “1,000-Meter Zone” shall be restricted by shunting all drill 

cuttings and drilling fluids to the bottom through a structurally sound downpipe 

that terminates at an appropriate distance, but no more than 10 m, from the 

bottom.

(c) Operations within a “1-Mile Zone” must be restricted by shunting all drill cuttings 

and drilling fluids to the bottom through a structurally sound downpipe that 

terminates at an appropriate distance, but no more than 10 m, from the bottom. 

(Where there is a “1-Mile Zone” designated, the “1,000-Meter Zone” in paragraph 

(b) is not designated.) This restriction on operations also applies to areas 

surrounding the Flower Garden Banks National Marine Sanctuary (i.e., the 

boundary as of the publication of this Multisale EIS), namely the “4-Mile Zone” 

surrounding the East Flower Garden Bank and the West Flower Garden Bank.

(d) Operations within a “3-Mile Zone” must be restricted by shunting all drill cuttings 

and drilling fluids from development operations to the bottom through a 

structurally sound downpipe that terminates at an appropriate distance, but no 

more than 10 m, from the bottom. If more than two exploration wells that are for 

purposes other than development operations are to be drilled from the same 

surface location, all drill cuttings and drilling fluids must be restricted by shunting 

to the bottom through a structurally sound downpipe that terminates at an 

appropriate distance, but no more than 10 meters, from the bottom.

The Topographic Features Stipulation, together with the appropriate Topographic Features 

Stipulation Map, will be included only in leases issued as a result of a lease sale on blocks within the 

areas so indicated in the Western and Central Gulf of Mexico Topographic Features Stipulation Map 

Package, which is available from the BOEM’s Gulf of Mexico OCS Region’s Public Information 

Office at 1-800-200-GULF and on BOEM’s website at http://www.boem.gov/Topo-Stip-MapPackage/. As referenced in paragraphs (a)-(d) of this stipulation, a Topographic Features Stipulation 

Map will be attached to each lease instrument subject to this stipulation.
D-6 Gulf of Mexico Multisale EIS

The banks and corresponding blocks to which this stipulation may be applied in the WPA are 

as follows:

Shelf Edge Banks Low-Relief Banks2 South Texas Banks4

Bank Name Isobath (m) Bank Name Isobath (m) Bank Name Isobath (m)

West Flower 

Garden Bank

(defined by 

1⁄4 1⁄4 1⁄4 system)

100

Mysterious Bank 74, 76, 78, 80, 84 Dream Bank 78, 82

Coffee Lump Various Southern Bank 80

East Flower 

Garden Bank

(defined by 

1⁄4 1⁄4 1⁄4 system)

100

Blackfish Ridge 70 Hospital Bank 70

Big Dunn Bar 65 North Hospital 

Bank 68

MacNeil Bank 82 Small Dunn Bar 65 Aransas Bank 70

29 Fathom Bank 64 32 Fathom Bank 52 South Baker 

Bank 70

Rankin Bank 85 Claypile Bank3 50 Baker Bank 70

Bright Bank1 85

Stetson Bank 52

Appelbaum 

Bank 85

1 CPA bank with a portion of its “3-Mile Zone” in the WPA.

2 Low-Relief Banks—only paragraph (a) of the stipulation applies. 3 Claypile Bank—only paragraphs (a) and (b) of the stipulation apply. In paragraph (b), monitoring of the 

effluent to determine the impact on the biota of Claypile Bank shall be required rather than shunting. 4 South Texas Banks—only paragraphs (a) and (b) of the stipulation apply.
Proposed Prelease Mitigating Measures (Stipulations) D-7 

The banks and corresponding blocks to which this stipulation may be applied in the CPA are 

as follows:

Bank Name Isobath (m) Bank Name Isobath (m)

McGrail Bank 85 Jakkula Bank 85

Bouma Bank 85 Sweet Bank1 85

Rezak Bank 85 Bright Bank3 85

Sidner Bank 85 Geyer Bank 85

Sackett Bank2 85 Elvers Bank 85

Ewing Bank 85 Alderdice Bank 80

Diaphus Bank2 85 Fishnet Bank2 76

Parker Bank 85 Sonnier Bank 55

1 Only paragraph (a) of the stipulation applies.

2 Only paragraphs (a) and (b) of the stipulation apply.

3 CPA bank with a portion of its “3-Mile Zone” in the WPA.

Effectiveness of the Lease Stipulation

The purpose of the stipulation is to protect the biota of the topographic features from adverse 

impacts due to routine oil and gas activities. Such impacts include physical damage from anchoring 

and rig emplacement and potential toxic and smothering impacts from muds and cuttings 

discharges. The Topographic Features Stipulation has been used on leases since 1973, and this 

experience shows conclusively that the stipulation effectively prevents damage to the biota of these 

banks from routine oil and gas activities. Anchoring related to oil- and gas-related activities on the 

sensitive portions of the topographic features has been prevented. Monitoring studies have 

demonstrated that the shunting requirements of the stipulations are effective in preventing the muds 

and cuttings from impacting the biota of the banks. The stipulation, if adopted for a proposed action, 

will continue to protect the biota of the banks, specifically as discussed below.

Mechanical damage resulting from oil- and gas-related operations is probably the single 

most serious impact to benthic habitat. Complying with the No Activity Zone designation of the 

Topographic Features Stipulation should completely eliminate this threat to the sensitive biota of 

WPA and CPA topographic features from activities resulting from a proposed action. The sensitive 

biota within the zones provided for in the Topographic Features Stipulation will thus be protected.

Several other impact-producing factors may threaten communities associated with 

topographic features. Vessel anchoring and structure emplacement result in physical disturbance of 

benthic habitat and are the most likely activities to cause permanent or long-lasting impacts to 

sensitive offshore habitats. Recovery from damage caused by such activities may take 10 or more 

years (depending on the maturity of the impacted community). Operational discharges (drilling muds 
D-8 Gulf of Mexico Multisale EIS

and cuttings, produced waters) may impact the biota of the banks due to turbidity and sedimentation, 

resulting in death to benthic organisms in large areas. Recovery from such damage may take 10 or 

more years (depending on the maturity of the impacted community). A loss of well control without 

the release of substantial amounts of oil could cause similar damage to benthic biota by 

resuspending sediments, causing turbidity and sedimentation, which could ultimately have a lethal 

impact on benthic organisms. Recovery from such damage may take up to 10 years (depending on 

the maturity of the impacted community). Oil spills will cause damage to benthic organisms if the oil 

contacts the organisms; such contact is unlikely except from spills related to blowouts. There have 

been few blowouts in the GOM. Structure removal using explosives can result in water turbidity, 

redeposition of sediments, and explosive shock-wave impacts. Recovery from such damage could 

take more than 10 years (depending on the maturity of the impacted community). The above 

activities, especially bottom-disturbing activities, have the greatest potential to severely impact the 

biota of topographic features. A proposed action, without the Topographic Features Stipulation or 

comparable mitigation, is expected to have a severe impact on the sensitive offshore habitats of the 

topographic features.

The stipulation provides different levels of protection for banks in different categories as 

defined by Rezak and Bright (1981). The categories and their definitions are as follows:

Category A: zone of major reef-building activity; maximum environmental 

protection recommended;

Category B: zone of minor reef-building activity; environmental protection strongly 

recommended;

Category C: zone of negligible reef-building activity, but crustose algae present; 

environmental protection recommended; and

Category D: zone of no reef-building and insignificant populations of crustose 

algae; additional protection not necessary.

The stipulation requires that all effluents within 1,000 m (3,281 ft) of Sackett, Fishnet, and 

Diaphus Banks, categorized by Rezak and Bright (1981) as Category C banks, be shunted into the 

nepheloid layer; the potentially harmful materials in drilling muds will be trapped in the bottom 

boundary layer and will not move up the banks where the biota of concern are located. Surface 

drilling discharge at distances greater than 1,000 m (3,281 ft) from the bank is not expected to 

impact the biota.

The stipulation protects the remaining banks (Category A and B banks) with even greater 

restrictions. Surface discharge will not be allowed within 1 nmi (1.2 mi; 1.9 km) of these more 

sensitive banks. Surface discharges outside of 1 nmi (1.2 mi; 1.9 km) are not expected to impact the 

biota of the banks, as adverse impacts from surface discharge are limited to 1,000 m (3,281 ft). 

However, it is possible that, when multiple wells are drilled from a single platform (surface location), 

typical during development operations, extremely small amounts of muds discharged more than 
Proposed Prelease Mitigating Measures (Stipulations) D-9 

1 nmi (1.2 mi; 1.9 km) from the bank may reach the bank. In order to eliminate the possible 

cumulative impact of muds discharged during development drilling, the stipulation imposes a 3-Mile 

Zone within which shunting of development well effluent is required.

The stipulation would prevent damage to the biota of the banks from routine oil- and gasrelated activities resulting from a proposed action, while allowing the development of nearby oil and 

gas resources. The stipulation will not protect the banks from the adverse impacts of an accident 

such as a large blowout on a nearby oil or gas operation.

D.2 LIVE BOTTOM STIPULATION

The Live Bottom Stipulation is intended to protect live bottoms and the associated hard 

bottom communities from damage and, at the same time, provide for recovery of potential oil and 

gas resources. This stipulation has been routinely applied to appropriate CPA oil and gas lease 

sales since 1974 to protect known pinnacle trend features. This stipulation has also been applied to 

appropriate oil and gas lease sales since 1982 to protect known low-relief features; however, blocks 

subject to the Live Bottom (Low Relief) Stipulation (see below) have not been included in lease sales 

since the 1980s and that is not anticipated to change. Blocks subject to the Live Bottom (Low Relief) 

Stipulation are not included in the proposed actions for this Multisale EIS.

The Live Bottom (Pinnacle Trend) Stipulation covers the pinnacle trend area of the CPA 

(Figure 2-4). A small portion of the northeastern proposed CPA lease sale area is characterized by 

a pinnacle trend, which is classified as a live bottom under the stipulation. The pinnacles are a 

series of topographic irregularities with variable biotal coverage, which provide structural habitat for a 

variety of pelagic fish. The pinnacles trend features in the region could be impacted from physical

damage of unrestricted OCS oil- and gas-related activities, as noted in Chapter 4.6.2. More detail 

on the Live Bottom (Pinnacle Trend) Stipulation and the affected blocks can be found at 

http://www.boem.gov/Biologically-Sensitive-Areas-List/. 

In addition, all EPA blocks in water depths of 100 m (328 ft) or less and the following CPA 

blocks have known live bottom (low-relief) features that could also be subject to the stipulation: 

Pensacola Blocks 751-754, 793-798, 837-842, 881-886, 925-930, 969-975; and Destin Dome Blocks 

1-7, 45-51, 89-96, 133-140, 177-184, 221-228, 265-273, 309-317, 353-361, 397-405, 441-448, 

485-491, 529-534, 573-576. However, these blocks are not a part of a proposed action for this 

Multisale EIS. While none of the blocks with known concentrations of live bottom low-relief habitat 

are expected to be offered for lease, several live bottom low-relief areas are adjacent to blocks that 

would be offered for lease under a proposed action and could potentially be affected by impacts of 

routine activities and accidental events. Therefore, an analysis of the potential impacts is included in 

this Multisale EIS. More detail on the Live Bottom (Low-Relief) Stipulation and the affected blocks 

can be found at http://www.boem.gov/Biologically-Sensitive-Areas-List/. 
D-10 Gulf of Mexico Multisale EIS

The stipulation reads as follows:

Live Bottom Stipulation

For the purpose of this stipulation, “live bottom areas” are defined as seagrass 

communities; or those areas which contain biological assemblages consisting of 

such sessile invertebrates as sea fans, sea whips, hydroids, anemones, ascidians, 

sponges, bryozoans, or corals living upon and attached to naturally occurring hard or 

rocky formations with rough, broken, or smooth topography; or areas whose lithotope 

favors the accumulation of turtles, fishes, and other fauna.

Prior to any drilling activities or the construction or placement of any structure for 

exploration or development on this lease, including, but not limited to, anchoring, well 

drilling, and pipeline and platform placement, the lessee will submit to the BOEM 

Regional Director (RD) a live bottom survey report containing a bathymetry map 

prepared utilizing remote-sensing data and an interpretation of live bottom areas 

prepared from the data collected. The resultant bathymetry map shall be prepared 

for the purpose of determining the presence or absence of live bottoms which could 

be impacted by the proposed activity. This map shall encompass such an area of 

the seafloor where surface disturbing activities, including anchoring, may occur.

If the BOEM Regional Director determines that live bottoms might be adversely 

impacted by the proposed activity, the RD will require the lessee to undertake any 

measure deemed economically, environmentally, and technically feasible to protect 

the live bottom area. These measures may include, but are not limited to, relocation 

of operations, shunting of fluids and cuttings, and monitoring to assess the impact of 

the activity on the live bottoms.

Effectiveness of the Lease Stipulation

Through detection and avoidance, this stipulation minimizes the likelihood of mechanical 

damage from OCS oil- and gas-related activities associated with rig and anchor emplacement to the 

sessile and pelagic communities associated with the crest and flanks of such features. Since this 

area is subject to heavy natural sedimentation, this stipulation does not include any specific 

measures to protect the live bottoms from the discharge of effluents.

The sessile and pelagic communities associated with the crest and flanks of the live bottom 

features could be adversely impacted by oil- and gas-related activities resulting from a proposed 

action if such activities took place on or near these communities without the Live Bottom Stipulation. 

For many years, this stipulation has been made a part of leases on blocks in the CPA to ensure that 

pinnacle trend areas are mitigated to the greatest extent possible from nearby OCS oil- and gasrelated activities. This stipulation does not prevent the recovery of oil and gas resources; however, it 

does serve to protect valuable and sensitive biological resources.
Proposed Prelease Mitigating Measures (Stipulations) D-11

Activities resulting from a proposed action, particularly anchor damage to localized live 

bottom areas, would be expected to cause substantial damage to portions of these areas because 

these activities are potentially destructive to the biological communities and could damage one or 

several individual live bottom areas. The most potentially damaging of these are the impacts 

associated with mechanical damages that may result from anchors. However, the action is judged 

to be infrequent because of the limited operations in the vicinity of live bottoms and the small size of 

many of the features. Minor impact is expected from large oil spills, losses of well control, pipeline 

emplacement, muds and cuttings discharges, and structure removals. A proposed action, without 

the benefit of the Live Bottom Stipulation, could have an adverse impact on these areas, but such 

impact is expected to be localized in nature. Impact from mechanical damage, including anchors, 

could potentially be long term if the physical integrity of the live bottoms themselves became altered.

The pinnacle trend occurs as patchy regions within the general area of the eastern portion of 

the CPA (Ludwick and Walton, 1957; Barry A. Vittor and Associates, Inc., 1985; Brooks and 

Giammona, 1990). The pinnacle trend also extends into the EPA but not in the portion of the EPA 

proposed for leasing. The stipulation would require the operators to locate the individual pinnacles 

and associated communities that may be present in the block. Outside of the pinnacle trend, live 

bottom low-relief features can and do occur in isolated locations in shallow waters (<984 ft; 300 m) 

throughout the GOM wherever there is suitable hard substrate and other physical conditions (e.g., 

depth, turbidity, etc.) that allow for epibenthic community development (Rezak et al., 1990). 

However, they are primarily known to be present in some locations on the Mississippi-Alabama Shelf 

and in many more locations on the West Florida Shelf (Figure 4-16), which is far east of the 

proposed EPA lease sale area. The stipulation requires that a survey be done to encompass the 

potential area of proposed surface disturbance and that a bathymetry map depicting any live 

bottoms in the vicinity be prepared from the survey. BOEM’s Regional Director, through consultation 

with FWS, could then decide if live bottom features would be potentially impacted and, if so, require 

appropriate mitigating measures.

By identifying the live bottom features present at the activity site, the lessee would be 

directed to avoid placement of the drilling rig and anchors on the sensitive areas. Thus, mechanical 

damage to the live bottom features is eliminated when measures required by the stipulation are 

imposed. The rapid dilution of drill cuttings and muds will minimize the potential of significant 

concentration of effluents on live bottom features; therefore, the stipulation does not address effluent 

discharges.

D.3 MILITARY AREAS STIPULATION

The Military Areas Stipulation has been applied to all blocks leased in military areas since 

1977 and reduces potential impacts, particularly in regards to safety; but, it does not reduce or 

eliminate the actual physical presence of oil and gas operations in areas where military operations 

are conducted. The stipulation contains a “hold harmless” clause (holding the U.S. Government 

harmless in case of an accident involving military operations) and requires lessees to coordinate 

their activities with appropriate local military contacts. Figure 2-7 shows the military warning areas 
D-12 Gulf of Mexico Multisale EIS

in the Gulf of Mexico. As referenced in paragraph (a) of the stipulation, a list of the appropriate 

command headquarters will be included with each lease package subject to this stipulation.

Military Areas Stipulation

(a) Hold and Save Harmless

Whether compensation for such damage or injury might be due under a theory of 

strict or absolute liability or otherwise, the lessee assumes all risks of damage or 

injury to persons or property, which occur in, on, or above the OCS, to any persons 

or to any property of any person or persons who are agents, employees, or invitees 

of the lessee, its agents, independent contractors, or subcontractors doing business 

with the lessee in connection with any activities being performed by the lessee in, on, 

or above the OCS, if such injury or damage to such person or property occurs by 

reason of the activities of any agency of the United States (U.S.) Government, its 

contractors or subcontractors, or any of its officers, agents or employees, being 

conducted as a part of, or in connection with, the programs and activities of the 

command headquarters listed at the end of this stipulation.

Notwithstanding any limitation of the lessee's liability in Section 14 of the lease, the 

lessee assumes this risk whether such injury or damage is caused in whole or in part 

by any act or omission, regardless of negligence or fault, of the U.S. Government, its 

contractors or subcontractors, or any of its officers, agents, or employees. The 

lessee further agrees to indemnify and save harmless the U.S. Government against 

all claims for loss, damage, or injury sustained by the lessee, or to indemnify and 

save harmless the U.S. Government against all claims for loss, damage, or injury 

sustained by the agents, employees, or invitees of the lessee, its agents, or any 

independent contractors or subcontractors doing business with the lessee in 

connection with the programs and activities of the aforementioned military 

installation, whether the same be caused in whole or in part by the negligence or 

fault of the U.S. Government, its contractors, or subcontractors, or any of its officers, 

agents, or employees and whether such claims might be sustained under a theory of 

strict or absolute liability or otherwise.

(b) Electromagnetic Emissions

The lessee agrees to control its own electromagnetic emissions and those of its 

agents, employees, invitees, independent contractors or subcontractors emanating 

from individual designated defense warning areas in accordance with requirements 

specified by the commander, or his/her designee, of the command headquarters to 

the degree necessary to prevent damage to, or unacceptable interference with, 

Department of Defense flight, testing, or operational activities, conducted within 

individual designated warning areas. Necessary monitoring control, and coordination 

with the lessee, its agents, employees, invitees, independent contractors or 
Proposed Prelease Mitigating Measures (Stipulations) D-13

subcontractors, will be affected by the commander of the appropriate onshore 

military installation conducting operations in the particular warning area; provided, 

however, that control of such electromagnetic emissions shall in no instance prohibit 

all manner of electromagnetic communication during any period of time between a 

lessee, its agents, employees, invitees, independent contractors or subcontractors 

and onshore facilities.

(c) Operational

The lessee, when operating or causing to be operated on its behalf, boat, ship, or 

aircraft traffic in the individual designated warning areas, shall enter into an 

agreement with the commander, or his/her designee, of the individual command 

headquarters, upon utilizing an individual designated warning area prior to 

commencing such traffic. Such an agreement will provide for positive control of 

boats, ships, and aircraft operating in the warning areas at all times.

Effectiveness of the Lease Stipulation

The hold harmless section of the military stipulation serves to protect the U.S. Government 

from liability in the event of an accident involving the lessee and military activities. The actual 

operations of the military and the lessee and its agents will not be affected.

The electromagnetic emissions section of the stipulation requires the lessee and its agents to 

reduce and curtail the use of radio, CB, or other equipment emitting electromagnetic energy within 

some areas. This serves to reduce the impact of oil- and gas-related activity on the communications 

of military missions and reduces the possible impacts of electromagnetic energy transmissions on 

missile testing, tracking, and detonation.

The operational section requires notification to the military of oil- and gas-related activity to 

take place within a military use area. This allows the base commander to plan military missions and 

maneuvers that will avoid the areas where oil- and gas-related activities are taking place or to 

schedule around these activities. Prior notification helps reduce the potential impacts associated 

with vessels and helicopters traveling unannounced through areas where military activities are 

underway.

This stipulation reduces potential impacts, particularly in regards to safety, but it does not 

reduce or eliminate the actual physical presence of oil- and gas-related operations in areas where 

military operations are conducted. The reduction in potential impacts resulting from this stipulation 

makes multiple-use conflicts unlikely. Without the stipulation, some potential conflict is likely. The 

best indicator of the overall effectiveness of the stipulation may be that there has never been an 

accident involving a conflict between military operations and oil- and gas-related activities.
D-14 Gulf of Mexico Multisale EIS

D.4 EVACUATION STIPULATION

This stipulation would be a part of any lease in the easternmost portion of the CPA and all 

blocks leased in the EPA portion of the proposed lease sale area resulting from a proposed action. 

An evacuation stipulation has been applied to all blocks leased in these areas since 2001. The 

Evacuation Stipulation is designed to protect the lives and welfare of offshore oil and gas personnel. 

Oil- and gas-related activities have the potential to occasionally interfere with specific requirements 

and operating parameters for the lessee’s activities in accordance with the military stipulation 

clauses contained herein. If it is determined that the operations will result in interference with 

scheduled military missions in such a manner as to possibly jeopardize the national defense or to 

pose unacceptable risks to life and property, then a temporary suspension of operations and the 

evacuation of personnel may be necessary. The stipulation reads as follows:

Evacuation Stipulation

(a) The lessee, recognizing that oil and gas resource exploration, exploitation, 

development, production, abandonment, and site cleanup operations on the 

leased area of submerged lands may occasionally interfere with tactical military 

operations, hereby recognizes and agrees that the United States reserves and 

has the right to temporarily suspend operations and/or require evacuation on this 

lease in the interest of national security. Such suspensions are considered 

unlikely in this area. Every effort will be made by the appropriate military agency 

to provide as much advance notice as possible of the need to suspend 

operations and/or evacuate. Advance notice of fourteen (14) days shall normally 

be given before requiring a suspension or evacuation, but in no event will the 

notice be less than four (4) days. Temporary suspension of operations may 

include the evacuation of personnel, and appropriate sheltering of personnel not 

evacuated. Appropriate shelter means the protection of all lessee personnel for 

the entire duration of any Department of Defense activity from flying or falling 

objects or substances; it will be implemented by a written order from the BSEE 

Gulf of Mexico Region, Regional Supervisor for District Field Operations 

(RSDFO), after consultation with the appropriate command headquarters or other 

appropriate military agency, or higher authority. The appropriate command 

headquarters, military agency or higher authority will provide information to allow 

the lessee to assess the degree of risk to, and provide sufficient protection for, 

lessee’s personnel and property. Such suspensions or evacuations for national 

security reasons will not normally exceed seventy-two (72) hours; however, any 

such suspension may be extended by order of the RSDFO. During such periods, 

equipment may remain in place, but all production, if any, must cease for the 

duration of the temporary suspension if so directed by the RSDFO. Upon 

cessation of any temporary suspension, the RSDFO will immediately notify the 

lessee such suspension has terminated and operations on the leased area can 

resume.
Proposed Prelease Mitigating Measures (Stipulations) D-15

(b) The lessee shall inform the BSEE of the persons/offices to be notified to 

implement the terms of this stipulation.

(c) The lessee is encouraged to establish and maintain early contact and 

coordination with the appropriate command headquarters, in order to avoid or 

minimize the effects of conflicts with potentially hazardous military operations.

(d) The lessee is not entitled to reimbursement for any costs or expenses associated 

with the suspension of operations or activities or the evacuation of property or 

personnel in fulfillment of the military mission in accordance with subsections 

(a) through (c) above.

(e) Notwithstanding subsection (d), the lessee reserves the right to seek 

reimbursement from appropriate parties for the suspension of operations or 

activities or the evacuation of property or personnel associated with conflicting 

commercial operations.

Effectiveness of the Lease Stipulation

This stipulation would provide for the evacuation of personnel and shut-in of operations 

during any events conducted by the military that could pose a danger to ongoing oil- and gas-related 

operations. It is expected that the invocation of these evacuation requirements will be extremely 

rare.

It is expected that these measures will serve to eliminate dangerous conflicts between oiland gas-related operations and military operations. Continued close coordination between BSEE 

and the military may result in improvements in the wording and implementation of these stipulations.

D.5 COORDINATION STIPULATION

This stipulation would be a part of any lease in the easternmost portion of the CPA and all 

blocks leased in the EPA portion of the proposed leased sale area. A coordination stipulation has 

been applied to all blocks leased in these areas since 2001. The Coordination Stipulation is 

designed to increase communication and cooperation between military authorities and offshore oil 

and gas operators. Specific requirements and operating parameters are established for the lessee’s 

activities in accordance with the Military Stipulation clauses. For instance, if it is determined that the 

operations will result in interference with scheduled military missions in such a manner as to possibly 

jeopardize the national defense or to pose unacceptable risks to life and property, then certain 

measures become activated and the oil- and gas-related operations may be curtailed in the interest 

of national defense. The stipulation reads as follows and, as referenced in paragraph (a) of the 

stipulation, a list of military stipulation clauses will be included with each lease package subject to 

this stipulation.
D-16 Gulf of Mexico Multisale EIS

Coordination Stipulation

(a) The placement, location, and planned periods of operation of surface structures 

on this lease during the exploration stage are subject to approval by the BOEM 

Regional Director (RD) after the review of an operator’s EP. Prior to approval of 

the EP, the lessee shall consult with the appropriate command headquarters 

regarding the location, density, and the planned periods of operation of such 

structures, and to maximize exploration while minimizing conflicts with 

Department of Defense activities. When determined necessary by the 

appropriate command headquarters, the lessee will enter into a formal Operating 

Agreement with such command headquarters, that delineates the specific 

requirements and operating parameters for the lessee’s activities in accordance 

with the military stipulation clauses contained herein. If it is determined that the 

final operations will result in interference with scheduled military missions in such 

a manner as to possibly jeopardize the national defense or to pose unacceptable 

risks to life and property, then the BOEM RD may approve the EP with 

conditions, disapprove it, or require modification in accordance with 30 CFR 

part 550. The RD will notify the lessee in writing of the conditions associated 

with plan approval, or the reason(s) for disapproval or required modifications. 

Moreover, if there is a serious threat of harm or damage to life or property, or if it 

is in the interest of national security or defense, pending or approved operations 

may be suspended in accordance with 30 CFR part 250 or 30 CFR part 550. 

Such a suspension will extend the term of a lease by an amount equal to the 

length of the suspension. The BSEE RD will attempt to minimize such 

suspensions within the confine of related military requirements. It is recognized 

that the issuance of a lease conveys the right to the lessee as provided in section 

8(b)(4) of the Outer Continental Shelf Lands Act, 43 U.S.C. § 1337(b)(4), to 

engage in exploration, development, and production activities conditioned upon 

other statutory and regulatory requirements.

(b) The lessee is encouraged to establish and maintain early contact and 

coordination with the appropriate command headquarters, in order to avoid or 

minimize the effects of conflicts with potentially hazardous military operations.

(c) If national security interests are likely to be in continuing conflict with an existing 

Operating Agreement, EP, DPP, or DOCD, the BSEE RD, in consultation with 

BOEM, will direct the lessee to modify any existing operating agreement or to 

enter into a new operating agreement to implement measures to avoid or 

minimize the identified potential conflicts, subject to the terms and conditions and 

obligations of the legal requirements of the lease.
Proposed Prelease Mitigating Measures (Stipulations) D-17

Effectiveness of the Lease Stipulation

This stipulation would provide for review of pending oil and gas operations by military 

authorities and could result in delaying oil and gas operations if military activities have been 

scheduled in the area that may put the oil and gas operations and personnel at risk.

D.6 BLOCKS SOUTH OF BALDWIN COUNTY, ALABAMA, STIPULATION

This stipulation will be included only on leases on blocks south of and within 15 mi (24 km) of 

Baldwin County, Alabama. The stipulation reads as follows:

Blocks South of Baldwin County, Alabama, Stipulation

(a) In order to minimize visual impacts from development operations on this block, 

you will contact lessees and operators of leases in the vicinity prior to submitting 

a DOCD to determine if existing or planned surface production structures can be 

shared. If feasible, your DOCD should reflect the results of any resulting sharing 

agreement, propose the use of subsea technologies, or propose another 

development scenario that does not involve new surface structures.

(b) If you cannot formulate a feasible development scenario that does not call for 

new surface structure(s), your DOCD should ensure that they are the minimum 

necessary for the proper development of the block and that they will be 

constructed and placed, using orientation, camouflage, or other design 

measures, to limit their visibility from shore.

(c) The BOEM will review and make decisions on your DOCD in accordance with 

applicable Federal regulations and BOEM policies, and in consultation with the 

State of Alabama (Geological Survey/Oil and Gas Board).

Effectiveness of the Lease Stipulation

For several years, the Governor of Alabama has continually indicated opposition to new 

leasing south and within 15 mi (24 km) of Baldwin County but has requested that, if the area is 

offered for lease, a lease stipulation to reduce the potential for visual impacts should be applied to all 

new leases in this area. Prior to the decision in 1999 on the Final Notice of Sale for Lease Sale 172, 

BOEM’s Gulf of Mexico OCS Region’s Regional Director, in consultation with the Geological Survey 

of Alabama/State Oil and Gas Board, developed a lease stipulation to be applied to any new leases 

within the 15-mi (24-km) area to mitigate potential visual impacts. The stipulation specifies 

requirements for consultation that lessees must follow when developing plans for fixed structures. 

The stipulation has been continually adopted in annual CPA lease sales since 1999. It has been 

considered satisfactorily responsive to the concern of the Governor of Alabama and was adopted in 

each of the CPA lease sales in the previous three Five-Year Programs.
D-18 Gulf of Mexico Multisale EIS

D.7 PROTECTED SPECIES STIPULATION

The Protected Species Stipulation has been applied to all blocks leased in the GOM since 

December 2001. This stipulation was developed in consultation with the U.S. Department of 

Commerce, National Oceanic and Atmospheric Administration, NMFS and the U.S. Department of 

the Interior, FWS in accordance with Section 7 of the Endangered Species Act, and it is designed to 

minimize or avoid potential adverse impacts to federally protected species.

Protected Species Stipulation

A. The Federal Endangered Species Act (ESA; 16 U.S.C. §§ 1531-1544) and the 

Marine Mammal Protection Act (MMPA; 16 U.S.C. 1361-1423h) are designed to 

protect threatened and endangered species and marine mammals and apply to 

activities on the Outer Continental Shelf (OCS). The Outer Continental Shelf 

Lands Act (OCSLA; at 43 U.S.C. §§ 1331-1356a) provides that the OCS should 

be made available for expeditious and orderly development subject to 

environmental safeguards, in a manner which is consistent with the maintenance 

of competition and other national needs (see 43 U.S.C. § 1332). BOEM and 

BSEE comply with these laws on the OCS.

B. The lessee and its operators must:

(1) collect and remove flotsam resulting from activities related to exploration, 

development, and production of this lease;

(2) post signs in prominent places on all vessels and platforms used as a result 

of activities related to exploration, development, and production of this lease 

detailing the reasons (legal and ecological) why release of debris must be 

eliminated;

(3) observe for marine mammals and sea turtles while on vessels, reduce vessel 

speed to 10 knots or less when assemblages of cetaceans are observed, and 

maintain a distance of 91 meters or greater from whales, and a distance of 

45 meters or greater from small cetaceans and sea turtles;

(4) employ mitigation measures prescribed by BOEM/BSEE or the National 

Marine Fisheries Service (NMFS) for all seismic surveys, including the use of 

an “exclusion zone” based upon the appropriate water depth, ramp-up and 

shutdown procedures, visual monitoring, and reporting;

(5) identify important habitats, including designated critical habitat, used by listed 

species (e.g., sea turtle nesting beaches, piping plover critical habitat), in oil 

spill contingency planning and require the strategic placement of spill cleanup 

equipment to be used only by personnel trained in less-intrusive cleanup 

techniques on beaches and bay shores; and
Proposed Prelease Mitigating Measures (Stipulations) D-19

(6) immediately report all sightings and locations of injured or dead protected 

species (e.g., marine mammals and sea turtles) to the appropriate stranding 

network. If oil and gas industry activity is responsible for the injured or dead 

animal (e.g., because of a vessel strike), the responsible parties should 

remain available to assist the stranding network. If the injury or death was 

caused by a collision with the lessee’s vessel, the lessee must notify BSEE 

within 24 hours of the strike in accordance with NTL No. 2012-JOINT-G01 

(Vessel Strike Avoidance and Injured/Dead Protected Species Reporting).

C. BOEM and BSEE issue Notices to Lessees (NTLs) which more fully describe 

measures implemented in support of the above-mentioned implementing statutes 

and regulations, as well as measures identified by the U.S. Fish and Wildlife 

Service and NMFS arising from, among others, conservation recommendations, 

rulemakings pursuant to the MMPA, or consultation. The lessee and its 

operators, personnel, and subcontractors, while undertaking activities authorized 

under this lease, must implement and comply with the specific mitigation 

measures outlined in: NTL No. 2012-JOINT-G01, NTL No. 2012-JOINT-G02 

(Implementation of Seismic Survey Mitigation Measures and Protected Species 

Observer Program), and NTL No. 2012-BSEE-G01 (Marine Trash and Debris 

Awareness and Elimination). At the lessee’s option, the lessee, its operators, 

personnel and contractors may comply with the most current measures to protect 

species in place at the time an activity is undertaken under this lease, including 

but not limited to new or updated versions of the NTLs identified in this 

paragraph. The lessee and its operators, personnel and subcontractors will be 

required to comply with the mitigation measures, identified in the above 

referenced NTLs, and additional measures in the conditions of approvals for their 

plans or permits.

Effectiveness of the Lease Stipulation

This stipulation was developed in consultation with NMFS and FWS, and is designed to 

minimize or avoid potential adverse impacts to federally protected species. The stipulation 

minimizes certain activities and stops others when those actions have the potential to impact marine 

mammals or sea turtles. These avoidance criteria provide protection by ensuring the animals remain 

a safe distance from the operations or the activity ceases.

D.8 UNITED NATIONS CONVENTION ON THE LAW OF THE SEA ROYALTY PAYMENT 

STIPULATION

If the United States becomes a party to the 1982 United Nations Convention on the Law of 

the Sea (UNCLOS) prior to or during the life of a lease issued by the United States on a block or 

portion of a block located beyond its Exclusive Economic Zone as defined in UNCLOS, and subject 

to such conditions that the Senate may impose through its constitutional role of advice and consent, 
D-20 Gulf of Mexico Multisale EIS

then the royalty payment lease provisions will apply to the lease so issued, consistent with Article 82 

of UNCLOS.

Law of the Sea Convention Royalty Payment Stipulation

(A) UNCLOS requires payments annually by coastal states party to the Convention 

with respect to all production at a site after the first five years of production at that 

site. Any such payments will be made by the U.S. Government and not the 

lessee.

(B) For the purpose of this stipulation regarding payments by the lessee to the U.S., 

each lease constitutes a separate site, whether or not a lease is committed to a 

unit.

(C) For the purpose of this stipulation, the first production year begins on the first day 

of commercial production (excluding test production). Once a production year 

begins, it will run for a period of 365 days whether or not the lease produces 

continuously in commercial quantities. Subsequent production years shall begin 

on the anniversary date of first production.

(D) If total lease production during the first five years following first production 

exceeds the total royalty suspension volume(s) provided in the lease terms, or 

through application and approval of relief from royalties, the following provisions 

of this stipulation will not apply. If, after the first five years of production, but prior 

to termination of this lease, production exceeds the total royalty suspension 

volume(s) provided in the lease terms or through application and approval of 

relief from royalties, the provisions of this stipulation will no longer apply effective 

the day after the suspension volumes have been produced.

(E) If, in any production year after the first five years of lease production, due to 

lease royalty suspension provisions or through application and approval of relief 

from royalties, no lease production royalty is due or payable by the lessee to the 

U.S., then the lessee will be required to pay, as stipulated in paragraph I below, 

Convention-related royalty in the following amount so that the required 

Convention payments may be made by the U.S. Government, as provided under 

the Convention:

(1) In the sixth year of production, 1 percent of the value of the sixth year's lease 

production saved, removed, or sold from the leased area;

(2) After the sixth year of production, the Convention-related royalty payment 

rate shall increase by 1 percent for each subsequent year until the twelfth 

year and shall remain at 7 percent thereafter until lease termination.

(F) If the U.S. becomes a party to UNCLOS after the fifth year of production from the 

lease, and a lessee is required, as provided herein, to pay Convention-related 
Proposed Prelease Mitigating Measures (Stipulations) D-21

royalty, the amount of the royalty due will be based on the above payment 

schedule as determined from first production. For example, the U.S. 

Government becomes a party to the UNCLOS in the tenth year of lease 

production resulting in a UNCLOS-related royalty payment of 5 percent of the 

value of the tenth year's lease production, saved, removed, or sold from the 

lease. The following year, a payment of 6 percent would be due, and so forth, as 

stated above, up to a maximum of 7 percent per year.

(G) If, in any production year after the first five years of lease production, due to 

lease royalty suspension provisions or through application and approval of relief 

from royalties, lease production royalty is paid but is less than the payment 

provided for by the Convention, then the lessee will be required to pay to the U.S. 

Government the UNCLOS-related royalty in the amount of the shortfall.

(H) In determining the value of production from the lease if a payment of UNCLOSrelated royalty is to be made, the provisions of the lease and applicable 

regulations will apply.

(I) The UNCLOS-related royalty payment(s) required under paragraphs E through G 

of this stipulation, if any, shall not be paid monthly but will be due and payable to 

the Office of Natural Resources Revenue on or before 30 days after the 

expiration of the relevant production lease year.

(J) The lessee will receive royalty credit in the amount of the UNCLOS-related 

royalty payment required under paragraphs E through G of this stipulation, which 

will apply to royalties due under the lease for which the Convention-related 

royalty accrued in subsequent periods, as non-UNCLOS-related royalty 

payments become due.

(K) Any lease production for which the lessee pays no royalty other than a 

UNCLOS-related requirement, due to lease royalty suspension provisions or 

through application and approval of relief from royalties, will count against the 

lease's applicable royalty suspension or relief volume.

(L) The lessee will not be allowed to apply or recoup any unused UNCLOS-related 

credit(s) associated with a lease that has been relinquished or terminated.

D.9 BELOW SEABED OPERATIONS STIPULATION

The stipulation language below is intended to be lease sale-specific language and would 

incorporate maps of the blocks that may be affected by the Below Seabed Operations Stipulation.

Below Seabed Operations Stipulation

Rights-of-use and easements have been granted to allow permanent mooring of 

floating production facilities. As a result, any lessee holding an interest in oil and gas 
D-22 Gulf of Mexico Multisale EIS

leases for these blocks is not allowed to conduct activities, including, but not limited 

to, the construction and use of structures, operation of drilling rigs, laying of 

pipelines, and/or anchoring, will occur or be located on the seafloor or in the water 

column within the areas depicted by the attached maps. Subseabed activities that 

are part of exploration, development, and production activities from outside the areas 

depicted by the attached maps may be allowed, including the use of directional 

drilling or other techniques.

This stipulation will be included in any lease awarded from this sale on the following 

list of blocks.

Mississippi Canyon 650, 651, 692, 694, 723, 735, 767, 919, 920, 921, and 964

Walker Ridge 293 and 294, 717, 762, and 763

Green Canyon 613, 786, 787, 788, and 860

Keathley Canyon 831

Effectiveness of the Lease Stipulation

This stipulation is designed to minimize or avoid potential space-use conflicts with moored 

and/or floating production facilities that have already been granted rights-of-use and easements in 

particular OCS blocks. BOEM has effectively used this stipulation for over a decade to make 

bidders aware of other activities with rights-of-use and easements on the above OCS blocks and 

may require buffers or additional requirements prior to acquiring leases on those specific blocks.

D.10 TRANSBOUNDARY STIPULATION

Agreement between the United States of America 

and the United Mexican States Concerning 

Transboundary Hydrocarbon Reservoirs in the Gulf of Mexico Stipulation

The “Agreement between the United States of America and the United Mexican 

States Concerning Transboundary Hydrocarbon Reservoirs in the Gulf of Mexico” 

(Agreement) signed on February 20, 2012, entered into force on July 18, 2014. All 

activities carried out under this lease must comply with the Agreement and any law, 

regulation, or condition of approval of a unitization agreement, plan, or permit 

adopted by the United States to implement the Agreement before or after issuance of 

this lease. The lessee is subject to, and must comply with, all terms of the 

Agreement, including, but not limited to, the following requirements:

This Agreement makes it possible for U.S. lessees to enter into voluntary 

agreements with a licensee of the United Mexican States (e.g., Petróleos Mexicanos

(PEMEX)) to develop transboundary reservoirs. Lessees in the Boundary Area may 

be subject to certain provisions of the Agreement.
Proposed Prelease Mitigating Measures (Stipulations) D-23

A. When the United States is obligated under the Agreement to provide information 

that may be considered confidential, commercial, or proprietary to a third-party or 

the Government of the United Mexican States, if the lessee holds such 

information, the lessee is required to provide it to the lessor as provided for in the 

Agreement;

B. When the United States is obligated under the Agreement to prohibit 

commencement of production on a lease, the Bureau of Safety and 

Environmental Enforcement (BSEE) will direct a Suspension of Production with 

which the lessee must comply;

C. When the United States is obligated under the Agreement to seek development 

of a transboundary reservoir under a unitization agreement, the lessee is 

required to cooperate and explore the feasibility of such development with a 

licensee of the United Mexican States;

D. When there is a proven transboundary reservoir, as defined by the Agreement, 

and the relevant parties, including the lessee, fail to conclude a unitization 

agreement, the lessee’s rights to produce the hydrocarbon resources will be 

limited by the terms of the Agreement;

E. If the lessee seeks to jointly explore or develop a transboundary reservoir with a 

licensee of the United Mexican States, the lessee is required to submit to BSEE 

information and documents that comply with and contain terms consistent with 

the Agreement, including, but not limited to, a proposed unitization agreement 

that designates the unit operator for the transboundary unit and provides for the 

allocation of production and any redetermination of the allocation of production; 

and

F. The lessee is required to comply with and abide by determinations issued as a 

result of the Agreement’s dispute resolution process on, among other things, the 

existence of a transboundary reservoir, and the allocation and/or reallocation of 

production.

The lessee and its operators, personnel, and subcontractors are required to comply 

with these and any other additional measures necessary to implement the provisions 

of the Agreement, including, but not limited to, conditions of approvals for their plans 

and permits for activities related to any transboundary reservoir or geologic structure 

subject to the Agreement.

The term “Boundary Area,” means an area comprised of any and all blocks in the 

Western and Central Planning Areas, that are located wholly or partially within three 

statute miles of the Maritime and Continental Shelf boundary with Mexico, as the 

Maritime Boundary is delimited in the Treaty to Resolve Pending Boundary 

Differences and Maintain the Rio Grande and Colorado River as the International 
D-24 Gulf of Mexico Multisale EIS

Boundary, signed November 24, 1970; the Treaty on Maritime Boundaries between 

the United Mexican States and the United States of America, signed on May 4, 1978; 

and, as the continental shelf in the Western Gulf of Mexico beyond 200 nautical miles 

is delimited in the Treaty between the Government of the United Mexican States and 

the Government of the United States of America, signed on June 9, 2000.

A copy of the Agreement can be found at the Department of the Interior website at: 

http://www.boem.gov/BOEM-Newsroom/Library/Boundaries-Mexico.aspx. 

Effectiveness of the Lease Stipulation

The Transboundary Agreement removes uncertainties regarding development of 

transboundary resources in the resource-rich Gulf of Mexico. As a result of the agreement, nearly 

1.5 million ac of the OCS will now be made more accessible for exploration and production activities. 

BOEM’s estimates indicate that this area contains as much as 172 million barrels of oil and 

304 billion cubic feet of natural gas. The Agreement also opens up resources in the Western Gap 

that were off limits to both countries under a previous treaty that imposed a moratorium along the 

boundary. The Transboundary Agreement sets clear guidelines for the development of oil and 

natural gas reservoirs that cross the maritime boundary. Under the Agreement, U.S. companies and 

PEMEX will be able to voluntarily enter into agreements to jointly develop those reservoirs. In the 

event that consensus cannot be reached, the Transboundary Agreement establishes the process 

through which U.S. companies and PEMEX can individually develop the resources on each side of 

the border while protecting each nation's interests and resources.

D.11 REFERENCES

Barry A. Vittor and Associates, Inc. 1985. Tuscaloosa Trend regional data search and synthesis 

study. Volume I: Synthesis report. U.S. Dept. of the Interior, Minerals Management Service, 

Gulf of Mexico OCS Region, Metairie, LA. OCS Study MMS 85-0056. 398 pp.

Bright, T.J. and R. Rezak. 1978. Northwestern Gulf of Mexico topographic features study: Final 

report. U.S. Dept. of the Interior, Bureau of Land Management, New Orleans OCS Office, New 

Orleans, LA. Study No. 1978-4. 692 pp. Internet website: http://www.gomr.boemre.gov/PI/

PDFImages/ESPIS/3/4069.pdf. 

Brooks, J.M. and C.P. Giammona. 1990. Mississippi-Alabama marine ecosystem study: Annual 

report; year 2. Volume I: Technical narrative. U.S. Dept. of the Interior, Minerals Management 

Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS Study MMS 89-0095. 348 pp.

Ludwick, J.C. and W.R. Walton. 1957. Shelf-edge, calcareous prominences in the northeastern 

Gulf of Mexico. Bulletin of the American Association of Petroleum Geologists 41(9):2054-2101.

National Research Council (NRC). 1983. Drilling discharges in the marine environment. Panel on 

Assessment of Fates and Effects of Drilling Fluids and Cuttings in the Marine Environment. 

National Research Council, Commission on Engineering and Technical Systems, Marine Board. 

Washington, DC: National Academy Press. Pp. 18-21.
Proposed Prelease Mitigating Measures (Stipulations) D-25

Rezak, R. and T.J. Bright. 1981. Northern Gulf of Mexico topographic features study: Final report. 

U.S. Dept. of the Interior, Bureau of Land Management, Gulf of Mexico OCS Region, New 

Orleans, LA. Contract No. AA551-CT8-35. 5 vols.

Rezak, R., T.J. Bright, and D.W. McGrail. 1983. Reefs and banks of the northwestern Gulf of 

Mexico: Their geological, biological, and physical dynamics. Final Technical Report No. 83-1-T.

Rezak, R., T.J. Bright, and D.W. McGrail. 1985. Reefs and banks of the northwestern Gulf of 

Mexico: Their geological, biological, and physical dynamics. New York, NY: Wiley and Sons. 

259 pp.

Rezak, R., S.R. Gittings, and T.J. Bright. 1990. Biotic assemblages and ecological controls on reefs 

and banks of the northwest Gulf of Mexico. American Zoologist 30:23-35.

APPENDIX E 

OIL SPILL RISK ANALYSIS FIGURES

Oil Spill Risk Analysis Figures E-3 

E OIL SPILL RISK ANALYSIS FIGURES

The following figures comprise the results of the Oil Spill Risk Analysis (OSRA) conducted 

for Alternatives A, B, and C. All of the assumptions and scenario estimates for Alternative D 

(including the commonly applied mitigating measures in Appendix B) are the same as for a 

proposed action under Alternative A, B, or C; consequently, refer to the corresponding Alternative A, 

B, or C for information relevant to Alternative D. Chapter 3.2.1 of this Multisale EIS provides for a 

discussion of oil spills and the OSRA model. In summary, oil-spill risk was calculated by multiplying 

the probability of contact generated by the OSRA model by the probability of occurrence of one or 

more spills ≥1,000 bbl as a result of a proposed action. This provides a risk factor that represents 

the probability of a spill occurring as a result of a proposed action and contacting a specified 

geographic area or feature. These are referred to as “combined probabilities” because they combine 

the risk of occurrence of a spill from OCS sources and the risk of such a spill contacting areas of 

sensitive environmental, social, and economic resources. Figure E-1 shows the geographic 

boundaries, known as the domain, used for the analysis. Figure E-2 through Figure E-7 show the 

probabilities of oil spills (≥1,000 bbl) occurring and contacting within 10 or 30 days the shoreline 

(counties and parishes) as a result of an Alternative A, B, or C proposed action. Figure E-8 through

Figure E-19 show the probabilities of oil spills (≥1,000 bbl) occurring and contacting within 10 or 

30 days nearshore (0-20 m), shelf (20-300 m), and deepwater (300 m to outer jurisdiction) areas as 

a result of the low- or high-case scenario of resource estimates for Alternatives A, B, or C. Lastly, 

Figure E-20 shows the probabilities of oil spills (≥1,000 bbl) occurring and contacting within 10 days 

and 30 days State offshore waters as a result of Alternative A, B, or C.
E-4 Gulf of Mexico Multisale EIS

Figure E-1. The Oil Spill Risk Analysis Domain.

Figure E-2. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days the Shoreline 

(counties and parishes) as a Result of Alternative A.
Oil Spill Risk Analysis Figures E-5 

Figure E-3. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days the Shoreline 

(counties and parishes) as a Result of Alternative A.

Figure E-4. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days the Shoreline 

(counties and parishes) as a Result of Alternative B.
E-6 Gulf of Mexico Multisale EIS

Figure E-5. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days the Shoreline 

(counties and parishes) as a Result of Alternative B.

Figure E-6. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days the Shoreline 

(counties and parishes) as a Result of Alternative C.
Oil Spill Risk Analysis Figures E-7 

Figure E-7. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days the Shoreline 

(counties and parishes) as a Result of Alternative C.

Figure E-8. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days Nearshore 

(“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to outer jurisdiction) 

Polygons as a Result of the Low Case in Resource Estimates for Alternative A. 
E-8 Gulf of Mexico Multisale EIS

Figure E-9. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days Nearshore 

(“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to outer jurisdiction) 

Polygons as a Result of the High Case in Resource Estimates for Alternative A. 

Figure E-10. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days Nearshore 

(“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to outer jurisdiction) 

Polygons as a Result of the Low Case in Resource Estimates for Alternative A. 
Oil Spill Risk Analysis Figures E-9 

Figure E-11. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days Nearshore 

(“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to outer jurisdiction) 

Polygons as a Result of the High Case in Resource Estimates for Alternative A. 

Figure E-12. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days Nearshore 

(“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to outer jurisdiction) 

Polygons as a Result of the Low Case in Resource Estimates for Alternative B. 
E-10 Gulf of Mexico Multisale EIS

Figure E-13. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days Nearshore 

(“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to outer jurisdiction) 

Polygons as a Result of the High Case in Resource Estimates for Alternative B. 

Figure E-14. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days Nearshore 

(“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to outer jurisdiction) 

Polygons as a Result of the Low Case in Resource Estimates for Alternative B. 
Oil Spill Risk Analysis Figures E-11

Figure E-15. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days Nearshore 

(“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to outer jurisdiction) 

Polygons as a Result of the High Case in Resource Estimates for Alternative B. 

Figure E-16. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days Nearshore 

(“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to outer jurisdiction) 

Polygons as a Result of the Low Case in Resource Estimates for Alternative C. 
E-12 Gulf of Mexico Multisale EIS

Figure E-17. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days Nearshore 

(“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to outer jurisdiction) 

Polygons as a Result of the High Case in Resource Estimates for Alternative C. 

Figure E-18. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days Nearshore 

(“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to outer jurisdiction) 

Polygons as a Result of the Low Case in Resource Estimates for Alternative C. 
Oil Spill Risk Analysis Figures E-13

Figure E-19. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 30 Days Nearshore 

(“N”, 0-20 m), Shelf (“S”, 20-300 m), and Deepwater (“D”, 300 m to outer jurisdiction) 

Polygons as a Result of the High Case in Resource Estimates for Alternative C. 

Figure E-20. Probabilities of Oil Spills (≥1,000 bbl) Occurring and Contacting within 10 Days and 30 Days 

State Offshore Waters as a Result of Alternative A, B, or C. (Note: The limits of State 

waters are defined by the States and range from 3 to 9 nmi [3.45 to 10.36 mi; 5.56 to 

16.67 km]. Texas and Florida State offshore waters extend 3 marine leagues [just over 

9 nmi] seaward from the shoreline [1 marine league = 18,228.3 ft; 5,556 m]. Louisiana 

State offshore waters extend 3 imperial nautical miles seaward of the shoreline [1 imperial 

nautical mile = 6,080 ft; 1,853 m].

APPENDIX F 

SPECIES NOT CONSIDERED FURTHER

Species not Considered Further F-3 

F SPECIES NOT CONSIDERED FURTHER 

Common Name Scientific Name

Mammals

Bats

Florida bonneted bat Eumops floridanus

Gray bat Myotis grisescens

Indiana bat Myotis sodalis

Rodents

Anastasia Island beach mouse Peromyscus polionotus phasma

Florida salt marsh vole Microtus pennsylvanicus dukecampbelli

Key Largo cotton mouse Peromyscus gossypinus allapaticola

Key Largo woodrat Neotoma floridana smalli

Rice rat Oryzomys palustris natator

Santa Rosa beach mouse Peromyscus polionotus leucocephalus

Southeastern beach mouse Peromyscus polionotus niveiventris

Other Mammals

Florida panther Puma concolor coryi

Gulf Coast jaguarundi Herpailurus yagouaroundi cacomitli

Key deer Odocoileus virginianus clavium

Louisiana black bear Ursus americanus luteolus

Lower Keys marsh rabbit Sylvilagus palustris hefneri

Ocelot Leopardus pardalis

Puma Puma concolor (all subspecies except coryi)

Birds

Attwater's greater prairie-chicken Tympanuchus cupido attwateri

Audubon's crested caracara Polyborus plancus audubonii

Bachman's warbler Vermivora bachmanii

Ivory-billed woodpecker Campephilus principalis

Everglade snail kite Rostrhamus sociabilis plumbeus

Florida grasshopper sparrow Ammodramus savannarum floridanus

Florida scrub-jay Aphelocoma coerulescens

Kirtland's warbler Setophaga kirtlandii

Least tern Sterna antillarum

Northern aplomado falcon Falco femoralis septentrionalis

Red-cockaded woodpecker Picoides borealis

Red crowned parrot Amazona viridigenalis

Sprague's pipit Anthus spragueii
F-4 Gulf of Mexico Multisale EIS

Common Name Scientific Name

Reptiles

Alabama red-belly turtle Pseudemys alabamensis

American alligator Alligator mississippiensis

American crocodile Crocodylus acutus

Atlantic salt marsh snake Nerodia clarkii taeniata

Black pine snake Pituophis melanoleucus lodingi

Eastern indigo snake Drymarchon corais couperi

Gopher tortoise Gopherus polyphemus

Ringed map turtle Graptemys oculifera

Sand skink Neoseps reynoldsi

Yellow-blotched map turtle Graptemys flavimaculata

Amphibians

Dusky gopher frog Rana sevosa

Frosted flatwoods salamander Ambystoma cingulatum

Reticulated flatwoods salamander Ambystoma bishopi

Striped newt Notophthalmus perstriatus

Fishes

Alabama shad Alosa alabamae

Alabama sturgeon Scaphirhynchus suttkusi

Atlantic sturgeon Acipenser oxyrinchus oxyrinchus

Caribbean electric ray Narcine bancroftii

Dusky shark Carcharhinus obscurus

Gulf sturgeon Acipenser oxyrinchus desotoi

Key silverside Menidia conchorum

Largetooth sawfish Pristis pristis

Nassau grouper Epinephelus striatus

Okaloosa darter Etheostoma okaloosae

Opossum pipefish Microphis brachyurus lineatus

Pallid sturgeon Scaphirhynchus albus

Pearl darter Percina aurora

Sand tiger shark Charcharias taurus

Shortnose sturgeon Acipenser brevirostrum

Smalltooth sawfish Pristis pectinata

Speckled hind (grouper) Epinephelus drummondhayi

Warsaw grouper Epinephelus nigritus
Species not Considered Further F-5 

Common Name Scientific Name

Invertebrates

Coral

Ivory tree coral Oculina varicosa 

Pillar coral Dendrogyra cylindrus

Rough cactus coral Mycetophyllia ferox

Clams

Alabama heelsplitter Potamilus inflatus

Chipola slabshell Elliptio chipolaensis

Choctaw bean Villosa choctawensis

Fat threeridge Amblema neislerii

Fuzzy pigtoe Pleurobema strodeanum

Golden orb Quadrula aurea

Gulf moccasinshell Medionidus penicillatus

Narrow pigtoe Fusconaia escambia

Ochlockonee moccasinshell Medionidus simpsonianus

Oval pigtoe Pleurobema pyriforme

Purple bankclimber Elliptoideus sloatianus

Round ebonyshell Fusconaia rotulata

Shinyrayed pocketbook Lampsilis subangulata

Smooth pimpleback Quadrula houstonensis

Southern kidneyshell Ptychobranchus jonesi

Southern sandshell Hamiota australis

Tapered pigtoe Fusconaia burkei

Texas fawnsfoot Truncilla macrodon

Texas pimpleback Quadrula petrina

Snails

Stock Island tree snail Orthalicus reses

Insects

Bartram's hairstreak butterfly Strymon acis bartrami

Florida leafwing butterfly Anaea troglodyta floridalis

Miami blue butterfly Cyclargus thomasi bethunebakeri

Schaus swallowtail butterfly Heraclides aristodemus ponceanus

Fungi

Florida perforate cladonia Cladonia perforata
F-6 Gulf of Mexico Multisale EIS

Common Name Scientific Name

Plants

Ferns and Allies

Florida bristle fern Trichomanes punctatum ssp. floridanum

Louisiana quillwort Isoetes louisianensis

Conifers and Cycads

Florida torreya Torreya taxifolia

Flowering Plants

Aboriginal prickly-apple Harrisia aboriginum

American chaffseed Schwalbea americana

Apalachicola rosemary Conradina glabra

Beach jacquemontia Jacquemontia reclinata

Beautiful pawpaw Deeringothamnus pulchellus

Big pine partridge pea Chamaecrista lineata keyensis

Black lace cactus Echinocereus reichenbachii var. albertii

Blodgett's silverbush Argythamnia blodgettii

Britton's beargrass Nolina brittoniana

Brooksville bellflower Campanula robinsiae

Cape Sable thoroughwort Chromolaena frustrata

Carter's small-flowered flax Linum carteri carteri

Carter's mustard Warea carteri

Chapman rhododendron Rhododendron chapmanii

Cooley's meadowrue Thalictrum cooleyi

Cooley's water-willow Justicia cooleyi

Crenulate lead-plant Amorpha crenulata

Deltoid spurge Chamaesyce deltoidea ssp. Deltoidea

Etonia rosemary Conradina etonia

Everglades bully Sideroxylon reclinatum ssp. austrofloridense

Florida golden aster Chrysopsis floridana

Florida pineland crabgrass Digitaria pauciflora

Florida semaphore cactus Consolea corallicola

Florida bonamia Bonamia grandiflora

Florida brickell-bush Brickellia mosieri

Florida prairie-clover Dalea carthagenensis floridana

Florida skullcap Scutellaria floridana

Four-petal pawpaw Asimina tetramera

Fragrant prickly-apple Cereus eriophorus var. fragrans

Garber's spurge Chamaesyce garberi
Species not Considered Further F-7 

Common Name Scientific Name

Flowering Plants (continued)

Gentian pinkroot Spigelia gentianoides

Godfrey's butterwort Pinguicula ionantha

Harper's beauty Harperocallis flava

Johnson's seagrass Halophila johnsonii

Key tree cactus Pilosocereus robinii

Lakela's mint Dicerandra immaculata

Lewton's polygala Polygala lewtonii

Longspurred mint Dicerandra cornutissima

Miccosukee gooseberry Ribes echinellum

Okeechobee gourd Cucurbita okeechobeensis ssp. okeechobeensis

Papery whitlow-wort Paronychia chartacea

pigeon wings Clitoria fragrans

pineland sandmat Chamaesyce deltoidea pinetorum

Pygmy fringe-tree Chionanthus pygmaeus

Rugel's pawpaw Deeringothamnus rugelii

Sand flax Linum arenicola

Scrub buckwheat Eriogonum longifolium var. gnaphalifolium

Scrub plum Prunus geniculata

Slender rush-pea Hoffmannseggia tenella

Small's milkpea Galactia smallii

South Texas ambrosia Ambrosia cheiranthifolia

Telephus spurge Euphorbia telephioides

Texas prairie dawn-flower Hymenoxys texana

Texas ayenia Ayenia limitaris

Tiny polygala Polygala smallii

Wedge spurge Chamaesyce deltoidea serpyllum

White birds-in-a-nest Macbridea alba

Wide-leaf warea Warea amplexifolia

APPENDIX G 

STATE COASTAL MANAGEMENT PROGRAMS

State Coastal Management Programs G-3 

G STATE COASTAL MANAGEMENT PROGRAMS

Each State’s Coastal Management Program (CMP), federally approved by the National 

Oceanic and Atmospheric Administration (NOAA), is a comprehensive statement setting forth 

objectives, enforceable policies or guidelines, and standards for public and private use of land and 

water resources and uses in that State’s coastal zone. The program provides for direct State land 

and water use planning and regulations. The plan also includes a definition of what constitutes 

permissible land uses and water uses. Federal consistency is the Coastal Zone Management Act 

(CZMA) requirement where Federal agency activities that have reasonably foreseeable effects on 

any land or water use or natural resource of the coastal zone must be consistent to the maximum 

extent practicable with the enforceable policies or guidelines of a coastal state’s federally approved 

coastal management program. The latest Federal consistency regulations concerning State coastal 

zone management (CZM) programs are found in the Federal Register (2000 and 2006).

Each Gulf States’ official coastal boundary can be identified from NOAA’s website at 

https://coast.noaa.gov/czm/media/StateCZBoundaries.pdf. Once a State’s CMP is federally 

approved, Federal agencies must ensure that their actions are consistent to the maximum extent 

practicable with the enforceable polices of the approved program. Federal agencies provide 

feedback to the States through each Section 312 evaluation conducted by NOAA.

To ensure conformance with State CMP policies or guidelines and local land use plans, the 

Bureau of Ocean Management (BOEM) prepares a Federal consistency determination for each 

proposed Outer Continental Shelf (OCS) lease sale. Through the designated State CZM agency, 

local land use entities are provided numerous opportunities to comment on the OCS Program. Local 

land-use agencies also have the opportunity to comment directly to BOEM at any time, as well as 

during formal public comment periods related to the announcement of the Five-Year Program, Call 

for Information/Notice of Intent, environmental impact statement (EIS) scoping, public hearings on 

the Draft EIS, and the Proposed Notice of Sale.

A State’s approved CMP may also provide for the State’s review of OCS plans, permits, and 

license activities to determine whether they will be conducted in a manner consistent with the State’s 

CMP. This review authority is applicable to activities conducted in any area that has been leased 

under the OCS Lands Act (OCSLA) and that affect any land or water use or natural resource within 

the State’s coastal zone (16 U.S.C. § 1456(c)(3)(B)).

State of Texas Coastal Management Program

The Texas Coastal Management Program (TCMP) Final EIS was published in August 1996. 

On December 23, 1996, NOAA approved the TCMP, and the requirements therein were made 

operational as of January 10, 1997. The TCMP is based primarily on the Coastal Coordination Act 

(CCA) of 1991 (33 Tex. Nat. Res. Code Ann. Ch. 201 et seq.), as amended by House Bill 3226 

(1995), which calls for the development of a comprehensive coastal program based on existing 

statutes and regulations. The CCA established the geographic scope of the program by identifying 

the program’s inland, interstate, and seaward boundaries. The program’s seaward boundary is the 
G-4 Gulf of Mexico Multisale EIS

State’s territorial seaward limit (3 leagues or 10.36 miles or 16.67 kilometers). The State’s inland 

boundary is based on the State’s Coastal Facilities Designation Line (CFDL). The CFDL was 

developed in response to the Oil Pollution Act of 1990 and basically delineates those areas within 

which oil spills could affect coastal waters or resources. For the purposes of the TCMP, the CFDL 

has been modified to capture wetlands in upper reaches of tidal waters. The geographic scope also 

extends upstream 200 miles (322 kilometers) from the mouths of rivers draining into coastal bays 

and estuaries in order to manage water appropriations on those rivers. The program’s boundaries 

encompass all or portions of 18 coastal counties (including Cameron, Willacy, Kenedy, Kleberg, 

Nueces, San Patricio, Aransas, Refugio, Calhoun, Victoria, Jackson, Matagorda, Brazoria, 

Galveston, Harris, Chambers, Jefferson, and Orange Counties), roughly 8.9 million acres (3.6 million 

hectares) of land and water.

Within this coastal zone boundary, the scope of the TCMP’s regulatory program is focused 

on the direct management of 16 generic “Areas of Particular Concern,” called coastal natural 

resource areas (CNRAs). These CNRAs are associated with valuable coastal resources or 

vulnerable or unique coastal areas and include the following: waters of the open Gulf of Mexico 

(GOM); waters under tidal influence; submerged lands; coastal wetlands; seagrasses; tidal sand and 

mud flats; oyster reefs; hard substrate reefs; coastal barriers; coastal shore areas; GOM beaches; 

critical dune areas; special hazard areas; critical erosion areas; coastal historic areas; and coastal 

preserves.

The State has designated the Western Planning Area (WPA) as the geographical area in 

which Federal consistency shall apply outside of the coastal boundary. The TCMP also identifies 

Federal lands excluded from the State’s coastal zone, such as U.S. Department of Defense facilities 

and wildlife refuges.

Land and water uses subject to the program generally include the siting, construction, and 

maintenance of electric generating and transmission facilities; oil and gas exploration and 

production; and the siting, construction, and maintenance of residential, commercial, and industrial 

development on beaches, critical dune areas, shorelines, and within or adjacent to critical areas and 

other CNRAs. Associated activities also subject to the program include canal dredging; filling; 

placement of structures for shoreline access and shoreline protection; on-site sewage disposal, 

storm-water control, and waste management for local governments and municipalities; the siting, 

construction, and maintenance of public buildings and public works such as dams, reservoirs, and 

flood control projects and associated activities; the siting, construction, and maintenance of roads, 

highways, bridges, causeways, airports, railroads, and nonenergy transmission lines and associated 

activities; certain agricultural and silvicultural activities; water impoundments and diversions; and the 

siting, construction, and maintenance of marinas, State-owned fishing cabins, artificial reefs, public 

recreational facilities, structures for shoreline access and shoreline protection, boat ramps, and 

fishery management measures in the GOM.

The TCMP is a networked program that is implemented primarily through 8 State agencies, 

18 local governments, and the Coastal Coordination Advisory Committee (Committee). The 
State Coastal Management Programs G-5 

program relies primarily on direct State control of land and water uses, although local governments 

will implement State guidelines related to beach and dune management. Implementation and 

enforcement of the coastal policies is primarily the responsibility of the networked agencies and local 

governments through their existing statutes, regulatory programs, or other authorizations. 

Networked agencies include the General Land Office/School Land Board, Texas Commission on 

Environmental Quality, Railroad Commission of Texas, Texas Parks and Wildlife Commission, Texas 

Department of Transportation, Texas Water Development Board, Texas State Soil and Water 

Conservation Board, and the Texas Sea Grant College Program at Texas A&M University. Other 

members on the Council include four gubernatorial appointees: (1) a coastal business 

representative; (2) an agriculture representative; (3) a local elected official; and (4) a coastal citizen. 

Similarly, 18 county and municipal governments, in those counties with barrier islands, are also 

networked entities with responsibilities for program implementation vis-a-vis beaches and dunes.

Regulations, programs, and expertise of State, Federal, and local government entities are 

linked to the management of Texas CNRAs in the TCMP. Local governments are notified of relevant 

TCMP decisions, including those that may conflict with local land-use plans or zoning ordinances. 

The Committee includes a local government representative as a full-voting member. An additional 

local government representative can be added to the Committee as a non-voting member for special 

local matters under review. The Committee established a permanent advisory committee to ensure 

effective communication for local governments with land-use authority.

In 1994, this Agency entered into a Memorandum of Understanding (MOU) with the Texas 

General Land Office to address similar mineral resource management responsibilities between the 

two entities and to encourage cooperative efforts and promote consistent regulatory practices. This 

MOU, which encompasses a broad range of issues and processes, outlines the responsibilities and 

cooperative efforts, including leasing and CZMA review processes, agreed to by the respective 

agencies. Effective January 10, 1997, all operators were required to submit to BOEM certificates of 

consistency with the TCMP for proposed operations in the WPA.

This Agency developed coordination procedures with the State for submittal of offshore lease 

sale consistency determinations and plans of operation. The WPA Lease Sale 168 was this 

Agency’s first Federal action subject to State consistency review. This Agency and the State of 

Texas revised CZM consistency information for OCS plans, permits, and licenses to conform to the 

revised CZM regulations that were effective January 8, 2001, and updated on January 5, 2006, and 

have also incorporated streamlining improvements into the latest Notices to Lessees and Operators 

(NTLs) (NTLs 2008-G04, 2009-G27, and 2015-BOEM-N01). The State of Texas requires an 

adequate description, objective, and schedule for the project; site-specific information on the 

onshore support base, support vessels, shallow hazards, oil-spill response, wastes and discharges, 

transportation activities, and air emissions; and a Federal consistency certification, assessment, and 

findings. The State’s requirements for Federal consistency review are based specifically on U.S. 

Department of the Interior’s (DOI’s) regulations at 30 CFR parts 250, 254, 256, and 550, and 

NOAA’s Federal consistency regulations at 15 CFR part 930. This Agency will be continuing a 

dialogue with the State of Texas on reasonably foreseeable coastal effects for pipelines and other 
G-6 Gulf of Mexico Multisale EIS

permits, and the result of these discussions will be incorporated into future updates of this Agency’s 

NTLs and/permitting procedures.

State of Louisiana, Office of Coastal Management

The statutory authority for Louisiana's coastal zone management program, the Louisiana 

Office of Coastal Management (LOCM), is the State and Local Coastal Resources Management Act 

of 1978 et seq. (Louisiana Administrative Code, Volume 17, Title 43, Chapter 7, Coastal 

Management, June 1990 revised). The State statute puts into effect a set of State coastal policies 

and coastal use guidelines that apply to coastal land and water use decisionmaking. A number of 

existing State regulations are also incorporated into the program, including those concerning oil and 

gas and other mineral operations; leasing of State lands for mineral operations and other purposes; 

hazardous waste and radioactive materials; management of wildlife, fish, other aquatic life, and 

oyster beds; endangered species; air and water quality; and the Louisiana Superport.

The State statute also authorized establishment of Special Management Areas. Included as 

Special Management Areas are the Louisiana Offshore Oil Port (LOOP) and the Marsh Island

Wildlife Refuge. For purposes of the CZMA, only that portion of LOOP within Louisiana’s coastal 

zone is part of the Special Management Area. In April 1989, the Louisiana Legislature created the 

Wetlands Conservation and Restoration Authority and established a Wetlands Conservation and 

Restoration Trust Fund to underwrite restoration projects. The Legislature also reorganized part of 

the Louisiana Department of Natural Resources (LDNR) by creating the Office of Coastal 

Restoration and Management.

Local governments (parishes) may assume management of uses of local concern by 

developing a local coastal program consistent with the State CMP. The State of Louisiana has 

10 approved local coastal management programs (Calcasieu, Cameron, Jefferson, Lafourche, 

Orleans, St. Bernard, St. James, Plaquemines, Terrebonne, and St. Tammany Parishes). In 

addition, two additional parishes, St. John the Baptist and St. Charles, have worked towards 

developing local coastal management programs. Eight other programs (Assumption, Iberia, 

Livingston, St. Charles, St. Martin, St. Mary, Tangipahoa, and Vermilion Parishes) have not been 

formally approved by NOAA. The parish planning and/or permits offices often serve as the 

permitting agency for projects limited to local concern. Parish-level programs, in addition to issuing 

permits for uses of local concern, also function as a commenting agency to Louisiana’s CZM 

agency, the LOCM, regarding permitting of uses of State concern.

Appendix C2 of the LOCM outlines the rules and procedures for the State’s local CMP. 

Under the LOCM, parishes are authorized, though not required, to develop local CMPs. Approval of 

these programs gives parishes greater authority in regulating coastal development projects that 

entail uses of local concern. Priorities, objectives, and policies or guidelines of local land use plans 

must be consistent with the policies and objectives of Act 361, the LOCM, and the State guidelines, 

except for a variance adopted in Section IV.D of Appendix C2 of the LOCM. The Secretaries of 

LDNR and Wildlife and Fisheries may jointly rule on an inconsistent local program based on local 
State Coastal Management Programs G-7 

environmental conditions or user practices. State and Federal agencies review parish programs 

before they are adopted.

The coastal use guidelines are based on seven general policies or guidelines. State 

concerns that could be relevant to an OCS lease sale and its possible direct effects or associated 

facilities and nonassociated facilities are (a) any dredge and fill activity that intersects more than one 

waterbody, (b) projects involving the use of State-owned lands or water bottoms, (c) national interest 

projects, (d) pipelines, and (e) energy facility siting and development. Some coastal activities of 

concern that could be relevant to a lease sale include wetland loss due to channel erosion from OCS 

traffic; activities near reefs and topographic highs; activities that might affect endangered, 

threatened, or commercially valuable wildlife; and potential socioeconomic impacts due to offshore 

development. Secondary and cumulative impacts to coastal resources such as onshore facility 

development, cumulative impacts from infrastructure development, salt intrusion along navigation 

channels, etc. are also of particular concern.

Effective August 1993, the LOCM required that any entity applying for permits to conduct 

activities along the coast must notify the landowner of the proposed activity. An affidavit must also 

accompany any permit application. Through this regulation, the State strives to minimize coastal 

zone conflicts.

This Agency and the State of Louisiana revised CZM consistency information for OCS plans, 

permits, and licenses to conform to the revised CZM regulations that were effective January 8, 2001, 

and updated on January 5, 2006, and have also incorporated streamlining improvements into the 

latest NTLs (NTLs 2008-G04, 2009-G27, and 2015-BOEM-N01). Federal consistency for right-ofway (ROW) pipelines is addressed in NTL 2007-G20. The State of Louisiana requires an adequate 

description, objective, and schedule for the project. Also, the State requires site-specific information 

on the onshore support base, support vessels, shallow hazards, oil-spill response, wastes and 

discharges (including any disposal of wastes within the State coastal zone and waters and 

municipal, parish, or State facilities to be used), transportation activities, air emissions, and 

secondary and cumulative impacts; and a Federal consistency certification, assessment, and 

findings. In addition, the State receives consistency reviews on a case-by-case basis for 

decommissioning activities within OCS Significant Sediment Blocks that the State utilizes marine 

mineral resources for restoration projects. The State requirements for Federal consistency review 

are based specifically on DOI’s regulations at 30 CFR parts 250, 254, 256, and 550, and NOAA’s 

Federal consistency regulations at 15 CFR part 930. BOEM is continuing a dialogue with the State 

of Louisiana on reasonably foreseeable coastal effects associated with pipelines and other permits, 

and the result of these discussions will be incorporated into future updates of the Bureau of Ocean 

Energy Management’s NTL’s and/or permitting procedures.

State of Mississippi Coastal Program

The Mississippi Coastal Program (MCP) is administered by the Mississippi Department of 

Marine Resources. The MCP is built around several enforceable goals that promote comprehensive 
G-8 Gulf of Mexico Multisale EIS

management of coastal resources and encourage a balance between environmental protection/

preservation and development in the coastal zone. The primary coastal management statute is the 

Coastal Wetlands Protection Law. Other major features of the MCP include statutes related to 

fisheries, air and water pollution control, surface and groundwater, cultural resources, and the 

disposal of solid waste in marine waters. The Department of Marine Resources, the Department of 

Environmental Quality, and the Department of Archives and History are identified collectively as the 

“coastal program agencies.” Mississippi manages coastal resources by regulation and by promoting 

activities that use resources in compliance with the MCP. The State developed a coastal wetlands 

use plan, which includes designated use districts in coastal wetlands and Special Management Area 

Plans that steer development away from fragile coastal resources and help to resolve user conflicts.

For the purposes of the coastal program, the coastal zone encompasses the three coastal 

counties of Hancock, Harrison, and Jackson and all coastal waters. The Mississippi coast has 

359 miles (594 kilometers) of shoreline, including the coastlines of offshore barrier islands (Cat, 

Ship, Horn, and Petit Bois Islands). According to NOAA, there are no approved local CMPs for the 

State of Mississippi. The Southern Mississippi Planning and Development District serves in an 

advisory capacity to the State coastal agencies.

This Agency developed coordination procedures with the State for submittal of offshore lease 

sale consistency determinations and plans of operation. This Agency and the State of Mississippi 

revised CZM consistency information for OCS plans, permits and licenses to conform to the revised 

CZM regulations that were effective January 8, 2001, and updated on January 5, 2006, and have 

also incorporated streamlining improvements into the latest NTLs (NTLs 2008-G04, 2009-G27, and 

2015-BOEM-N01). Federal consistency for ROW pipelines is addressed in NTL 2007-G20. The 

State of Mississippi requires an adequate description, objective, and schedule for the project; sitespecific information on the onshore support base, support vessels, shallow hazards, oil-spill 

response, wastes and discharges, transportation activities, and air emissions; and a Federal 

consistency certification, assessment, and findings. The State requirements for Federal consistency 

review are based specifically on DOI’s regulations at 30 CFR parts 250, 254, 256, and 550, and 

NOAA’s Federal consistency requirements at 15 CFR part 930. BOEM is continuing a dialogue with 

the State of Mississippi on reasonably foreseeable coastal effects associated with pipelines and 

other permits, and the result of these discussions will be incorporated into future updates of the 

Bureau of Ocean Energy Management’s NTL’s and/or permitting procedures.

State of Alabama Coastal Area Management Program

The Alabama Coastal Area Act (ACAA) provides statutory authority to review all coastal 

resource uses and activities that have a direct and significant effect on the coastal area. The 

Alabama Department of Conservation and Natural Resources (ADCNR) Lands Division, Coastal 

Section Office, the lead coastal management agency, is responsible for the management of the 

State’s coastal resources through the Alabama Coastal Area Management Program (ACAMP). The 

ADCNR is responsible for the overall management of the program, including fiscal and grants 

management and public education and information. The department also provides planning and 
State Coastal Management Programs G-9 

technical assistance to local governments and financial assistance to research facilities and units of 

local government when appropriate. The State Lands Division, Coastal Section, also has authority 

over submerged lands in regard to piers, marinas, bulkheads, and submerged land leases.

The Alabama Department of Environmental Management (ADEM) is responsible for coastal 

area permitting, regulatory, and enforcement functions. Most programs of ADCNR Coastal Section 

that require environmental permits or enforcement functions are carried out by the ADEM with the 

exception of submerged land issues. The ADEM has the responsibility of all permit, enforcement, 

regulatory, and monitoring activities, and the adoption of rules and regulations to carry out the 

ACAMP. The ADEM must identify specific uses or activities that require a State permit to be 

consistent with the coastal policies noted above and the more detailed rules and regulations 

promulgated as part of the ACAMP. Under the ACAA, State agency activities must be consistent 

with ACAMP policies and ADEM findings. Further, ADEM must make a direct permit-type review for 

uses that are not otherwise regulated at the State level. The ADEM also has authority to review 

local government actions and to assure that local governments do not unreasonably restrict or 

exclude uses of regional benefit. Ports and major energy facilities are designated as uses of 

regional benefit. The ADCNR Lands Division manages all lease sales of State submerged 

bottomlands and regulates structures placed on State submerged bottomlands.

Local governments have the option to participate in the ACAMP by developing local codes, 

regulations, rules, ordinances, plans, maps, or any other device used to issue permits or licenses. If 

these instruments are certified to be consistent with ACAMP, ADEM may allow the local government 

to administer them by delegating its permit authority, thereby eliminating the need for ADEM’s caseby-case review.

The South Alabama Regional Planning Commission provides ongoing technical assistance 

to ADCNR for Federal consistency, clearinghouse review, and public participation procedures. Uses 

subject to the Alabama’s CZM program are divided into regulated and nonregulated categories. 

Regulated uses are those that have a direct and significant impact on the coastal areas. These uses 

either require a State permit or are required by Federal law to be consistent with the management 

program. Uses that require a State permit must receive a certificate of compliance. Nonregulated 

uses are those activities that have a direct and significant impact on the coastal areas that do not 

require a State permit or Federal consistency certification. Nonregulated uses must be consistent 

with ACAMP and require local permits to be administered by ADEM.

This Agency developed coordination procedures with the State for submittal of offshore lease 

sale consistency determinations and plans of operation. This Agency and the State of Alabama 

have revised CZM consistency information for OCS plans, permits, and licenses to conform to the 

revised CZM regulations that were effective January 8, 2001, and updated on January 5, 2006, and 

have also incorporated streamlining improvements into the latest NTLs (NTLs 2008-G04, 2009-G27, 

and 2015-BOEM-N01). Federal consistency for ROW pipelines is addressed in NTL 2007-G20. The 

State of Alabama requires an adequate description, objective, and schedule for the project; sitespecific information on the onshore support base, support vessels, shallow hazards, oil-spill 
G-10 Gulf of Mexico Multisale EIS

response, wastes and discharges, transportation activities, and air emissions; and a Federal 

consistency certification, assessment, and findings. The State’s requirements for Federal 

consistency review are based specifically on DOI’s regulations at 30 CFR parts 250, 254, 256, and 

550, and NOAA’s Federal consistency requirements at 15 CFR part 930. BOEM is continuing a 

dialogue with the State of Alabama on reasonably foreseeable coastal effects associated with 

pipelines and other permits, and the result of these discussions will be incorporated into future 

updates of Bureau of Ocean Energy Management’s NTLs and/or permitting procedures.

State of Florida Coastal Management Program

For purposes of the CZMA, the State of Florida’s coastal zone includes the area 

encompassed by the State’s 67 counties and its territorial seas. Lands owned by the Federal 

Government and the Seminole and Miccosukee Indian tribes are not included in the State’s coastal 

zone; however, Federal activities in or outside the coastal zone, including those on Federal or Tribal 

lands, that affect any land or water or natural resource of the State’s coastal zone are subject to 

review by Florida under the CZMA. The Florida Coastal Management Act, codified as Chapter 380, 

Part II, Florida Statutes, authorized the development of a coastal management program. In 1981, 

the Florida Coastal Management Program (FCMP) was approved by NOAA.

The policies identified by the State of Florida as being enforceable in the FCMP are the 

24 chapters that NOAA approved for incorporation in the State’s program. The 2011 Florida 

Statutes are the most recent version approved by NOAA and include the listing of OCSLA permits 

under Subpart E and the addition of draft EAs and EISs as necessary data and information for 

Federal consistency review

A network of eight State agencies and five regional water management districts implement 

the FCMP’s 24 statutes. The water management districts are responsible for water quantity and 

quality throughout the State’s watersheds. The State agencies include the following: the 

Department of Environmental Protection (DEP), the lead agency for the FCMP and the State’s chief 

environmental regulatory agency and steward of its natural resources; the Department of Community 

Affairs, which serves as the State’s land planning and emergency management agency; the 

Department of Health, which, among other responsibilities, regulates on-site sewage disposal; the 

Department of State, Division of Historical Resources, which protects historic and archaeological 

resources; the Fish and Wildlife Conservation Commission, which protects and regulates fresh and 

saltwater fisheries, marine mammals, and birds and upland species, including protected species and 

the habitat used by these species; the Department of Transportation, which is charged with the 

development, maintenance, and protection of the transportation system; the Department of 

Agriculture and Consumer Services, which manages State forests and administers aquaculture and 

mosquito control programs; and the Governor’s Office of Planning and Budget, which plays a role in 

the comprehensive planning process.

Effective July 1, 2000, the Governor of Florida assigned the State’s responsibilities under the 

OCSLA to the Secretary of the Florida DEP. The DEP’s Office of Intergovernmental Programs 
State Coastal Management Programs G-11

coordinates the review of OCS plans with FCMP member agencies to ensure that the plan is 

consistent with applicable State enforceable policies and the Governor’s responsibilities under the 

Act.

This Agency developed coordination procedures with the State for the submittal of offshore 

lease sale consistency determinations and plans of operation. In 2003, this Agency and the State 

revised CZM consistency information for OCS plans, permits, and licenses to conform with the 

revised CZM regulations that were effective on January 8, 2001, and updated on January 5, 2006, 

and they have also incorporated streamlining improvements into the latest NTLs (NTLs 2008-G04, 

2009-G27, and 2015-BOEM-N01). Federal consistency for ROW pipelines is addressed in NTL 

2007-G20.

The State of Florida requires an adequate description, objective, and schedule for all 

activities associated with a project; specific information on the natural resources potentially affected 

by the proposed activities; and specific information on onshore support base, support vessels, 

shallow hazards, oil-spill response, wastes and discharges, transportation activities, and air 

emissions; and a Federal consistency certification, assessment, and findings. As identified by the 

State of Florida, the State enforceable policies that must be addressed for OCS oil- and gas-related 

activities are found at http://www.boem.gov/CZM-Program-Policies-for-GOM-States.aspx. These 

requirements have been incorporated into the Plans and Regional Oil-Spill Response NTLs. The 

State requirements for Federal consistency review are based on the requirements of State statutes, 

CZMA regulations at 15 CFR part 930, and DOI’s regulations at 30 CFR parts 250, 254, 256, and 

550. BOEM is continuing a dialog with the State of Florida on reasonably foreseeable coastal 

effects associated with OCS plans, pipelines, and other permits; the result of these discussions will 

be incorporated into future updates of the Bureau of Ocean Energy Management’s NTLs and/or 

permitting procedures.

REFERENCES

Federal Register. 2000. Coastal Zone Management Act federal consistency regulations. Final rule. 

65 FR 237, pp. 77124-77175, December 8, 2000.

Federal Register. 2006. Coastal Zone Management Act federal consistency regulations. Final rule. 

71 FR 3, pp. 788-831, January 5, 2006.

KEYWORD INDEX

Keyword Index Keywords-3 

KEYWORD INDEX

Air Quality, xv, xvi, xvii, xviii, xxii, xxix, 1-10, 1-11, 1-14, 2-28, 2-30, 2-32, 2-33, 2-35, 2-40, 3-3, 3-24, 

3-87, 3-121, 3-154, 3-172, 4-3, 4-4, 4-6, 4-11, 4-12, 4-13, 4-14, 4-15, 4-16, 4-18, 4-19, 4-23, 

4-25, 4-27, 4-28, 4-30, 4-31, 4-32, 4-33, 4-34, 4-35, 4-36, 4-37, 4-203, 4-204, 4-211, 4-213, 

4-214, 4-215, 4-286, 4-352, 4-437

Alternate Use, 1-14, 3-177

Alternative Energy, 1-11

Archaeological Resources, xv, xvii, xxvii, xxix, 1-10, 2-28, 2-32, 2-34, 2-44, 2-45, 3-11, 3-13, 3-15, 

3-16, 3-162, 3-183, 3-184, 4-3, 4-5, 4-83, 4-356, 4-357, 4-359, 4-361, 4-362, 4-363, 4-364, 

4-365, 4-366, 4-367, 4-368, 4-369, 4-370, 4-371, 4-439, 4-441

Artificial Reefs, xxvi, xxix, 1-10, 1-11, 2-28, 2-44, 3-3, 3-74, 3-75, 3-159, 3-160, 4-94, 4-110, 4-160, 

4-171, 4-195, 4-196, 4-199, 4-204, 4-211, 4-279, 4-289, 4-317, 4-324, 4-332, 4-333, 4-334, 

4-335, 4-336, 4-337, 4-341, 4-343, 4-344, 4-354, 4-355, 4-366, 4-367, 4-444

Beach Mice, xv, xvii, xxiv, 2-32, 2-34, 2-42, 4-3, 4-56, 4-81, 4-224, 4-225, 4-227, 4-228, 4-294, 

4-295, 4-296, 4-297, 4-298, 4-299, 4-300, 5-5 

Blowout Preventer, 3-19, 3-34, 3-53, 3-67, 3-120, 3-121, 4-243

Blowouts, 2-30, 3-11, 3-19, 3-29, 3-34, 3-53, 3-67, 3-95, 3-103, 3-104, 3-109, 3-119, 3-120, 3-121, 

3-132, 3-133, 4-29, 4-30, 4-113, 4-114, 4-115, 4-116, 4-174, 4-175, 4-243, 4-357, 4-366, 4-382, 

4-426

Catastrophic Spill, xxviii, 1-18, 2-4, 2-16, 2-21, 2-22, 2-29, 2-46, 3-96, 3-109, 3-113, 4-4, 4-8, 4-9, 

4-11, 4-29, 4-30, 4-31, 4-60, 4-64, 4-65, 4-73, 4-83, 4-86, 4-88, 4-92, 4-93, 4-112, 4-114, 4-115, 

4-116, 4-118, 4-119, 4-124, 4-153, 4-158, 4-173, 4-175, 4-179, 4-180, 4-253, 4-284, 4-349, 

4-365, 4-379, 4-382, 4-383, 4-401, 4-425, 4-427, 4-428, 4-433, 4-434, 4-436, 5-6, 5-9 

Chemosynthetic Communities, xix, xxix, 1-11, 2-28, 2-37, 3-11, 3-15, 3-33, 4-93, 4-98, 4-101, 4-102, 

4-103, 4-105, 4-108, 4-113, 4-118, 5-5 

Coastal and Marine Birds, xxii, xxiv, 2-40, 2-42, 4-127, 4-128, 4-205, 4-206, 4-210, 4-211, 4-213, 

4-214, 4-216, 4-219, 4-239, 4-303, 5-5 

Coastal Barrier Beaches, xvi, xix, 2-32, 2-34, 2-36, 4-3, 4-75, 4-81, 4-82, 4-84, 4-85, 4-86, 4-88, 

4-89, 4-90, 4-91, 4-92, 4-93, 4-228, 4-269, 4-295, 4-296, 4-297, 4-352, 4-390, 5-5 

Coastal Zone Management, xv, xxix, xxx, 1-10, 1-12, 1-17, 1-18, 1-20, 4-10, 4-41, 4-200, 5-3, 5-12, 

5-15

Collisions, xxiii, xxvii, 2-41, 2-45, 3-3, 3-123, 3-124, 3-125, 3-126, 3-163, 4-6, 4-84, 4-203, 4-212, 

4-214, 4-215, 4-217, 4-219, 4-220, 4-236, 4-241, 4-242, 4-254, 4-259, 4-272, 4-277, 4-281, 

4-293, 4-294, 4-306, 4-307, 4-373, 4-382, 4-383, 4-384, 4-385, 4-391, 4-400, 4-426, 4-427, 

4-428, 4-434, 4-437, 4-439
Keywords-4 Gulf of Mexico Multisale EIS

Commercial Fisheries, xv, xvii, xxv, 2-32, 2-34, 2-43, 4-3, 4-5, 4-246, 4-260, 4-313, 4-314, 4-316, 

4-317, 4-318, 4-319, 4-320, 4-321, 4-322, 4-400, 4-439, 4-441, 5-5 

Commercial Fishing, xv, xvii, xxv, 2-32, 2-34, 2-43, 4-3, 4-5, 4-246, 4-260, 4-313, 4-314, 4-316, 

4-317, 4-318, 4-319, 4-320, 4-321, 4-322, 4-400, 4-439, 4-441, 5-5 

Consultation and Coordination, 1-11, 1-12, 1-15, 1-18, 1-20, 3-95

Cumulative Activities, xiv, 1-20, 3-3, 3-146, 3-167, 3-173, 3-190, 3-197, 4-7, 4-32, 4-122, 4-299, 

4-379, 4-425

Cumulative Impacts, ix, xvi, xvii, xviii, xix, xx, xxi, xxii, xxiii, xxiv, xxv, xxvi, xxvii, xxviii, 2-21, 2-33, 

2-34, 2-35, 2-36, 2-37, 2-38, 2-39, 2-40, 2-41, 2-42, 2-43, 2-45, 2-46, 3-160, 3-177, 3-196, 4-3, 

4-5, 4-6, 4-10, 4-11, 4-13, 4-22, 4-31, 4-32, 4-33, 4-36, 4-37, 4-40, 4-47, 4-48, 4-50, 4-51, 4-63, 

4-66, 4-70, 4-71, 4-72, 4-73, 4-75, 4-76, 4-85, 4-90, 4-91, 4-92, 4-93, 4-94, 4-96, 4-115, 4-117, 

4-119, 4-120, 4-121, 4-122, 4-123, 4-133, 4-134, 4-135, 4-136, 4-137, 4-139, 4-142, 4-147, 

4-153, 4-155, 4-156, 4-157, 4-158, 4-159, 4-160, 4-176, 4-177, 4-179, 4-181, 4-182, 4-183, 

4-184, 4-185, 4-186, 4-191, 4-198, 4-199, 4-200, 4-201, 4-202, 4-203, 4-204, 4-210, 4-212, 

4-214, 4-215, 4-216, 4-218, 4-219, 4-220, 4-221, 4-222, 4-225, 4-227, 4-228, 4-240, 4-256, 

4-261, 4-264, 4-265, 4-275, 4-286, 4-291, 4-294, 4-295, 4-297, 4-298, 4-299, 4-300, 4-305, 

4-307, 4-308, 4-309, 4-311, 4-312, 4-313, 4-316, 4-318, 4-319, 4-320, 4-323, 4-324, 4-331, 

4-333, 4-338, 4-339, 4-343, 4-349, 4-351, 4-353, 4-354, 4-355, 4-356, 4-366, 4-371, 4-372, 

4-373, 4-384, 4-385, 4-386, 4-387, 4-391, 4-393, 4-398, 4-402, 4-405, 4-407, 4-410, 4-419, 

4-425, 4-427, 4-429, 4-430, 4-431, 4-434, 4-442, 5-7, 5-9, 5-10

Decommissioning, xvii, xxii, xxiii, xxvi, xxvii, xxix, 1-4, 1-7, 1-10, 1-14, 1-16, 1-19, 2-28, 2-35, 2-39, 

2-41, 2-44, 2-45, 3-3, 3-16, 3-46, 3-71, 3-72, 3-73, 3-75, 3-91, 3-151, 3-154, 3-159, 3-160, 

3-174, 3-196, 4-6, 4-11, 4-12, 4-23, 4-39, 4-43, 4-45, 4-94, 4-108, 4-110, 4-140, 4-141, 4-143, 

4-148, 4-150, 4-169, 4-171, 4-195, 4-196, 4-198, 4-202, 4-214, 4-227, 4-240, 4-245, 4-246, 

4-256, 4-257, 4-258, 4-276, 4-278, 4-279, 4-286, 4-289, 4-316, 4-317, 4-332, 4-333, 4-334, 

4-335, 4-336, 4-337, 4-341, 4-344, 4-351, 4-354, 4-355, 4-356, 4-362, 4-364, 4-367, 4-370, 

4-441, 5-17

Deepwater, xv, xvi, xix, xxi, xxiii, 1-15, 1-17, 1-18, 1-19, 2-3, 2-16, 2-17, 2-20, 2-21, 2-22, 2-29, 2-30, 

2-31, 2-32, 2-34, 2-37, 2-39, 2-41, 3-3, 3-17, 3-18, 3-19, 3-24, 3-26, 3-27, 3-29, 3-30, 3-32, 3-33, 

3-34, 3-36, 3-39, 3-41, 3-44, 3-46, 3-47, 3-58, 3-62, 3-63, 3-72, 3-79, 3-82, 3-85, 3-88, 3-91, 

3-93, 3-94, 3-95, 3-97, 3-98, 3-102, 3-104, 3-107, 3-109, 3-113, 3-115, 3-119, 3-120, 3-121, 

3-122, 3-125, 3-126, 3-129, 3-130, 3-131, 3-132, 3-133, 3-134, 3-136, 3-137, 3-138, 3-139, 

3-140, 3-141, 3-159, 3-174, 3-175, 3-176, 3-181, 3-182, 3-183, 3-190, 3-192, 3-193, 3-194, 

3-197, 3-198, 3-199, 3-204, 3-205, 4-3, 4-4, 4-7, 4-8, 4-9, 4-12, 4-24, 4-29, 4-30, 4-41, 4-49, 

4-54, 4-58, 4-64, 4-72, 4-78, 4-84, 4-86, 4-90, 4-91, 4-93, 4-94, 4-95, 4-96, 4-97, 4-98, 4-99, 

4-100, 4-101, 4-102, 4-103, 4-104, 4-105, 4-106, 4-107, 4-108, 4-109, 4-110, 4-111, 4-112, 

4-113, 4-114, 4-115, 4-116, 4-117, 4-118, 4-119, 4-120, 4-121, 4-122, 4-124, 4-129, 4-147, 

4-152, 4-156, 4-163, 4-169, 4-172, 4-173, 4-174, 4-175, 4-179, 4-180, 4-187, 4-193, 4-194, 

4-198, 4-201, 4-206, 4-210, 4-213, 4-218, 4-230, 4-231, 4-237, 4-242, 4-248, 4-252, 4-253, 

4-255, 4-261, 4-262, 4-263, 4-264, 4-265, 4-284, 4-286, 4-291, 4-292, 4-294, 4-307, 4-318, 
Keyword Index Keywords-5 

4-333, 4-348, 4-349, 4-360, 4-361, 4-365, 4-366, 4-374, 4-375, 4-376, 4-380, 4-382, 4-401, 

4-427, 4-428, 4-433, 4-434, 4-441, 4-443, 5-5, 5-9 

Deepwater Horizon, xv, xxiii, 1-17, 1-18, 2-3, 2-16, 2-17, 2-21, 2-22, 2-29, 2-31, 2-41, 3-79, 3-95, 

3-97, 3-98, 3-102, 3-104, 3-109, 3-113, 3-115, 3-119, 3-120, 3-121, 3-130, 3-131, 3-132, 3-133, 

3-134, 3-136, 3-137, 3-138, 3-139, 3-140, 3-141, 3-181, 3-182, 3-183, 3-190, 3-192, 3-193, 

3-194, 3-199, 3-205, 4-4, 4-7, 4-8, 4-12, 4-29, 4-30, 4-49, 4-54, 4-64, 4-72, 4-78, 4-84, 4-86, 

4-90, 4-91, 4-113, 4-115, 4-116, 4-118, 4-124, 4-129, 4-147, 4-156, 4-173, 4-174, 4-175, 4-179, 

4-206, 4-210, 4-213, 4-218, 4-253, 4-255, 4-261, 4-262, 4-263, 4-264, 4-265, 4-284, 4-291, 

4-292, 4-294, 4-307, 4-318, 4-333, 4-348, 4-349, 4-365, 4-366, 4-382, 4-401, 4-427, 4-428, 

4-433, 4-434, 5-9 

Demographics, 4-200, 5-5 

Discharges, xv, xviii, xix, xx, xxi, xxii, xxiii, xxiv, 2-23, 2-29, 2-30, 2-31, 2-35, 2-37, 2-38, 2-39, 2-40, 

2-41, 2-42, 3-3, 3-23, 3-53, 3-54, 3-55, 3-57, 3-58, 3-64, 3-65, 3-67, 3-68, 3-69, 3-70, 3-90, 

3-136, 3-154, 3-162, 3-163, 3-168, 3-169, 3-170, 3-171, 3-203, 4-6, 4-37, 4-38, 4-39, 4-42, 4-43, 

4-45, 4-47, 4-48, 4-59, 4-93, 4-96, 4-108, 4-109, 4-111, 4-116, 4-119, 4-124, 4-133, 4-142, 

4-144, 4-149, 4-151, 4-153, 4-159, 4-160, 4-169, 4-170, 4-171, 4-176, 4-180, 4-185, 4-203, 

4-204, 4-211, 4-214, 4-215, 4-219, 4-227, 4-240, 4-243, 4-244, 4-256, 4-257, 4-276, 4-278, 

4-286, 4-289, 4-290, 4-306, 4-343, 4-357, 4-437, 4-438

Dispersants, xviii, 2-36, 3-108, 3-110, 3-121, 3-129, 3-130, 3-131, 3-132, 3-136, 3-137, 3-138, 

3-139, 3-145, 4-30, 4-46, 4-65, 4-84, 4-112, 4-113, 4-114, 4-116, 4-118, 4-132, 4-136, 4-152, 

4-153, 4-173, 4-174, 4-176, 4-179, 4-213, 4-254, 4-255, 4-263, 4-284, 4-285, 4-366, 4-369, 

4-437, 4-438, 4-439

Dunes, xv, xvi, xix, xxiv, 2-32, 2-34, 2-36, 2-42, 3-194, 4-3, 4-54, 4-75, 4-76, 4-77, 4-79, 4-80, 4-81, 

4-82, 4-83, 4-84, 4-85, 4-86, 4-87, 4-88, 4-89, 4-90, 4-91, 4-92, 4-93, 4-127, 4-206, 4-228, 

4-269, 4-293, 4-294, 4-295, 4-296, 4-297, 4-298, 4-302, 4-351, 4-352, 4-390, 4-432, 5-5 

Economic Factors, xvii, xxvi, xxviii, 2-32, 2-34, 2-43, 2-44, 2-46, 4-3, 4-320, 4-321, 4-322, 4-334, 

4-335, 4-336, 4-337, 4-343, 4-347, 4-349, 4-353, 4-393, 4-398, 4-401, 4-420

Employment, 2-31, 4-331, 4-339, 4-340, 4-349, 4-372, 4-376, 4-380, 4-393, 4-394, 4-399, 4-401, 

4-402, 4-403, 4-404, 4-405, 4-406, 4-407, 4-408, 4-409, 4-411, 4-412, 4-413, 4-415, 4-417, 

4-419, 4-420, 4-425, 4-426, 4-428, 4-434, 4-435

Environmental Justice, xv, xvii, xxvii, xxviii, 2-3, 2-32, 2-34, 2-45, 2-46, 4-3, 4-418, 4-419, 4-431, 

4-435, 4-436, 5-5 

Essential Fish Habitat, 1-18, 1-19, 4-4, 4-10, 4-94, 4-138, 4-144, 4-161, 4-164, 4-187, 4-191, 4-198, 

4-319, 4-332, 4-341, 4-401, 5-3, 5-6, 5-17

Explosive Removals, 2-28, 4-246, 4-279

Fish Resources, 4-94, 4-161, 4-319, 4-332, 4-401
Keywords-6 Gulf of Mexico Multisale EIS

Fisheries, ix, xxv, xxvi, 1-12, 2-31, 2-43, 2-44, 3-66, 3-104, 3-159, 3-160, 3-183, 4-8, 4-138, 4-164, 

4-185, 4-186, 4-187, 4-189, 4-199, 4-201, 4-216, 4-231, 4-233, 4-235, 4-237, 4-261, 4-266, 

4-269, 4-273, 4-275, 4-287, 4-293, 4-313, 4-314, 4-316, 4-317, 4-318, 4-319, 4-320, 4-321, 

4-322, 4-324, 4-335, 4-336, 4-337

Flaring, xvii, xxix, 1-10, 2-30, 2-35, 3-37, 3-65, 3-89, 3-90, 3-121, 3-122, 3-123, 3-172, 4-11, 4-12, 

4-13, 4-23, 4-24, 4-25, 4-28, 4-29, 4-30, 4-31

Flower Garden Banks, x, xii, xxv, 1-17, 2-6, 2-10, 2-16, 2-28, 2-43, 4-144, 4-145, 4-147, 4-153, 

4-154, 4-155, 4-309, 4-310, 4-311, 4-312

Gulf Sturgeon, 2-20, 4-186

Human Resources, xvii, xxvii, 2-32, 2-34, 2-45, 4-5, 4-339, 4-371

Hurricanes, xv, xxvi, 1-14, 2-19, 2-29, 2-31, 2-43, 2-44, 3-3, 3-35, 3-48, 3-74, 3-77, 3-97, 3-98, 

3-103, 3-104, 3-105, 3-106, 3-115, 3-123, 3-124, 3-125, 3-127, 3-163, 3-175, 3-180, 3-188, 

3-189, 3-198, 3-199, 3-200, 4-4, 4-31, 4-33, 4-48, 4-54, 4-60, 4-64, 4-65, 4-66, 4-70, 4-71, 4-72, 

4-77, 4-78, 4-80, 4-86, 4-88, 4-89, 4-152, 4-153, 4-154, 4-174, 4-178, 4-210, 4-216, 4-260, 

4-261, 4-263, 4-266, 4-290, 4-291, 4-297, 4-298, 4-299, 4-309, 4-320, 4-321, 4-322, 4-334, 

4-335, 4-336, 4-337, 4-352, 4-361, 4-366, 4-369, 4-375, 4-432

Income, xxviii, 2-31, 2-46, 4-331, 4-341, 4-353, 4-393, 4-394, 4-395, 4-399, 4-402, 4-403, 4-404, 

4-405, 4-406, 4-407, 4-408, 4-409, 4-411, 4-412, 4-413, 4-415, 4-417, 4-419, 4-422, 4-430, 

4-431, 4-433, 4-435, 4-436

Infrastructure, xiv, xv, xvii, xxii, xxvii, xxviii, 1-5, 1-20, 2-14, 2-17, 2-31, 2-32, 2-34, 2-39, 2-45, 2-46, 

3-3, 3-4, 3-5, 3-7, 3-30, 3-35, 3-37, 3-39, 3-40, 3-42, 3-44, 3-45, 3-70, 3-73, 3-74, 3-75, 3-76, 

3-77, 3-84, 3-85, 3-96, 3-122, 3-123, 3-148, 3-151, 3-152, 3-154, 3-155, 3-158, 3-159, 3-178, 

3-180, 3-181, 3-183, 3-186, 3-191, 3-200, 4-3, 4-6, 4-10, 4-11, 4-33, 4-50, 4-51, 4-56, 4-58, 

4-64, 4-66, 4-69, 4-70, 4-75, 4-76, 4-81, 4-82, 4-85, 4-89, 4-91, 4-94, 4-95, 4-109, 4-110, 4-118, 

4-160, 4-162, 4-169, 4-170, 4-172, 4-176, 4-185, 4-194, 4-195, 4-196, 4-199, 4-202, 4-203, 

4-256, 4-257, 4-319, 4-332, 4-334, 4-341, 4-347, 4-349, 4-351, 4-355, 4-356, 4-363, 4-371, 

4-372, 4-373, 4-378, 4-379, 4-380, 4-381, 4-382, 4-383, 4-384, 4-385, 4-386, 4-387, 4-388, 

4-390, 4-391, 4-392, 4-400, 4-422, 4-425, 4-428, 4-429, 4-430, 4-431, 4-432, 4-436, 4-437, 

4-443

Land Use, xv, xvii, xxvii, xxx, 2-3, 2-31, 2-32, 2-34, 2-45, 3-75, 3-204, 4-3, 4-4, 4-5, 4-371, 4-372, 

4-373, 4-374, 4-376, 4-377, 4-379, 4-380, 4-381, 4-382, 4-383, 4-384, 4-385, 4-386, 4-387,

4-388, 4-390, 4-391, 4-392, 4-400, 4-436

Live Bottoms, xii, xiv, xv, xvi, xvii, xix, xx, xxi, xxv, xxvi, xxix, 1-19, 2-3, 2-11, 2-14, 2-23, 2-24, 2-27, 

2-32, 2-34, 2-37, 2-38, 2-39, 2-43, 2-44, 3-33, 3-192, 4-3, 4-5, 4-9, 4-11, 4-37, 4-50, 4-74, 4-93, 

4-94, 4-95, 4-97, 4-98, 4-99, 4-101, 4-103, 4-105, 4-106, 4-107, 4-109, 4-110, 4-112, 4-113, 

4-114, 4-116, 4-117, 4-118, 4-121, 4-137, 4-138, 4-139, 4-144, 4-145, 4-146, 4-148, 4-149, 

4-151, 4-152, 4-153, 4-154, 4-155, 4-157, 4-158, 4-159, 4-160, 4-161, 4-162, 4-163, 4-164, 

4-165, 4-167, 4-168, 4-169, 4-170, 4-171, 4-172, 4-173, 4-174, 4-175, 4-176, 4-177, 4-178, 
Keyword Index Keywords-7 

4-179, 4-180, 4-181, 4-182, 4-183, 4-184, 4-187, 4-198, 4-222, 4-223, 4-224, 4-225, 4-227, 

4-228, 4-271, 4-274, 4-285, 4-299, 4-308, 4-309, 4-310, 4-311, 4-312, 4-322, 4-324, 4-337, 

4-355, 4-392, 4-418, 4-435, 5-5 

Loss of Well Control, 2-29, 3-3, 3-95, 3-118, 3-119, 3-120, 3-130, 3-131, 4-6, 4-30, 4-112, 4-113, 

4-114, 4-153, 4-156, 4-173, 4-174, 4-175, 4-196, 4-250

Louisiana Highway 1, 4-379, 4-380

Low Relief, xvi, xxi, 2-24, 2-32, 2-34, 2-39, 3-33, 4-3, 4-96, 4-145, 4-147, 4-158, 4-159, 4-162, 4-164, 

4-165, 4-167, 4-168, 4-173, 4-178, 4-179, 4-180, 4-183, 4-188, 5-5 

Macondo, 3-120, 3-132, 3-133, 3-139, 3-141, 4-30, 4-114, 4-366

Mangroves, 3-145, 3-192, 4-53, 4-274, 4-302

Marine Mammals, ix, xv, xvi, xxiii, 1-16, 1-18, 2-20, 2-28, 2-31, 2-32, 2-34, 2-40, 2-41, 3-47, 3-91, 

3-94, 3-125, 3-162, 3-192, 3-194, 4-3, 4-10, 4-223, 4-224, 4-225, 4-227, 4-228, 4-229, 4-230, 

4-231, 4-233, 4-236, 4-237, 4-238, 4-239, 4-240, 4-241, 4-242, 4-243, 4-244, 4-245, 4-246, 

4-247, 4-248, 4-249, 4-250, 4-251, 4-252, 4-253, 4-254, 4-255, 4-256, 4-257, 4-258, 4-259, 

4-260, 4-261, 4-262, 4-263, 4-264, 4-265, 4-293, 4-438, 4-439, 5-5 

Mercury, 2-30, 3-37, 3-59, 3-60, 3-64, 3-166, 3-205, 4-39, 4-243

Meteorological Conditions, 3-109, 4-34, 4-35, 4-152

Mitigating Measures, ix, xiii, xiv, xviii, xix, xxix, 1-7, 1-10, 1-11, 1-17, 1-20, 2-5, 2-14, 2-17, 2-20, 

2-22, 2-23, 2-26, 2-27, 2-28, 2-36, 3-12, 3-182, 4-5, 4-9, 4-49, 4-50, 4-56, 4-73, 4-219, 4-241, 

4-289, 4-387, 4-431, 4-442, 5-17

Mitigation, ix, xiv, xviii, xx, xxi, xxiii, xxv, xxvii, xxix, 1-3, 1-11, 1-19, 2-12, 2-20, 2-22, 2-23, 2-26, 

2-28, 2-32, 2-35, 2-37, 2-39, 2-41, 2-43, 2-45, 3-42, 3-132, 3-158, 3-176, 3-191, 4-9, 4-13, 4-27, 

4-39, 4-40, 4-46, 4-47, 4-48, 4-56, 4-57, 4-58, 4-59, 4-66, 4-67, 4-68, 4-70, 4-73, 4-82, 4-85, 

4-96, 4-97, 4-108, 4-110, 4-111, 4-112, 4-115, 4-116, 4-118, 4-119, 4-120, 4-121, 4-122, 4-141, 

4-142, 4-148, 4-158, 4-159, 4-163, 4-169, 4-171, 4-172, 4-176, 4-177, 4-179, 4-180, 4-181, 

4-182, 4-183, 4-184, 4-187, 4-200, 4-203, 4-212, 4-215, 4-220, 4-241, 4-243, 4-245, 4-246, 

4-247, 4-256, 4-264, 4-276, 4-277, 4-278, 4-279, 4-285, 4-293, 4-298, 4-308, 4-311, 4-312, 

4-347, 4-349, 4-356, 4-357, 4-362, 4-363, 4-364, 4-366, 4-367, 4-368, 4-369, 4-370, 4-371, 

4-390, 4-432, 4-437, 4-439, 4-444, 5-7, 5-8, 5-10

NEPA, viii, 1-3, 1-4, 1-6, 1-7, 1-8, 1-9, 1-11, 1-13, 1-15, 1-16, 1-17, 1-18, 1-19, 2-3, 2-4, 2-16, 2-20, 

2-22, 2-27, 2-32, 3-94, 4-3, 4-6, 4-7, 4-10, 4-11, 4-49, 4-72, 4-91, 4-162, 4-201, 4-207, 4-219, 

4-231, 4-237, 4-246, 4-247, 4-334, 4-360, 4-369, 4-385, 4-390, 4-435, 5-3, 5-7, 5-8, 5-9, 5-10

Noise, xxii, xxiii, xxiv, 2-31, 2-40, 2-41, 2-42, 3-3, 3-13, 3-24, 3-47, 3-89, 3-90, 3-91, 3-92, 3-93, 

3-183, 4-6, 4-160, 4-192, 4-193, 4-198, 4-199, 4-201, 4-202, 4-203, 4-204, 4-211, 4-214, 4-219, 

4-227, 4-233, 4-240, 4-241, 4-242, 4-246, 4-247, 4-248, 4-249, 4-250, 4-255, 4-256, 4-257, 

4-259, 4-264, 4-276, 4-277, 4-280, 4-281, 4-286, 4-290, 4-306, 4-307, 4-352, 4-429, 4-438, 5-9 
Keywords-8 Gulf of Mexico Multisale EIS

Oil Spills, ix, xv, xvii, xviii, xix, xx, xxi, xxii, xxiii, xxiv, xxv, xxvi, xxvii, xxviii, xxx, 1-17, 1-18, 2-3, 2-16, 

2-17, 2-21, 2-22, 2-29, 2-31, 2-35, 2-36, 2-37, 2-38, 2-39, 2-40, 2-41, 2-42, 2-43, 2-44, 2-45, 

2-46, 3-3, 3-45, 3-79, 3-95, 3-96, 3-97, 3-98, 3-99, 3-102, 3-107, 3-109, 3-110, 3-111, 3-112, 

3-113, 3-114, 3-115, 3-116, 3-117, 3-118, 3-119, 3-120, 3-121, 3-128, 3-129, 3-130, 3-131, 

3-132, 3-133, 3-134, 3-136, 3-138, 3-139, 3-140, 3-141, 3-152, 3-162, 3-169, 3-192, 3-193, 

3-194, 3-198, 3-200, 3-205, 4-4, 4-6, 4-7, 4-8, 4-9, 4-11, 4-12, 4-13, 4-28, 4-29, 4-30, 4-31, 4-33, 

4-40, 4-46, 4-47, 4-48, 4-49, 4-50, 4-51, 4-54, 4-60, 4-62, 4-63, 4-64, 4-65, 4-68, 4-70, 4-72, 

4-73, 4-74, 4-75, 4-76, 4-78, 4-83, 4-84, 4-85, 4-86, 4-87, 4-90, 4-91, 4-92, 4-93, 4-96, 4-111, 

4-112, 4-113, 4-115, 4-116, 4-118, 4-119, 4-123, 4-124, 4-129, 4-130, 4-131, 4-133, 4-140, 

4-141, 4-142, 4-143, 4-147, 4-150, 4-151, 4-152, 4-154, 4-155, 4-156, 4-158, 4-159, 4-160, 

4-172, 4-173, 4-174, 4-175, 4-176, 4-180, 4-185, 4-186, 4-197, 4-203, 4-204, 4-206, 4-210, 

4-213, 4-214, 4-215, 4-218, 4-220, 4-221, 4-222, 4-227, 4-228, 4-250, 4-251, 4-252, 4-253, 

4-254, 4-255, 4-256, 4-257, 4-261, 4-262, 4-264, 4-265, 4-281, 4-282, 4-283, 4-284, 4-285, 

4-286, 4-287, 4-291, 4-292, 4-294, 4-296, 4-297, 4-299, 4-304, 4-307, 4-308, 4-313, 4-317, 

4-318, 4-320, 4-321, 4-322, 4-323, 4-332, 4-333, 4-335, 4-336, 4-337, 4-339, 4-348, 4-349, 

4-351, 4-352, 4-354, 4-355, 4-357, 4-365, 4-366, 4-369, 4-370, 4-373, 4-379, 4-382, 4-383, 

4-384, 4-385, 4-391, 4-400, 4-401, 4-411, 4-412, 4-415, 4-425, 4-426, 4-427, 4-428, 4-433, 

4-434, 4-437, 4-438, 4-439, 4-440, 4-441, 4-443, 5-9 

OSRA, xxix, 3-110, 3-111, 3-112, 3-113, 3-116, 4-253, 4-283, 4-296, 4-299

Physical Oceanography, 1-13, 3-197, 4-41, 4-370

Pinnacle Trend, xii, xiii, xiv, xv, xxi, xxix, 2-3, 2-11, 2-12, 2-24, 2-27, 2-39, 4-9, 4-11, 4-37, 4-50, 

4-74, 4-93, 4-113, 4-121, 4-137, 4-138, 4-157, 4-158, 4-162, 4-164, 4-165, 4-166, 4-167, 4-173, 

4-179, 4-181, 4-182, 4-183, 4-222, 4-299, 4-308, 4-312, 4-322, 4-337, 4-355, 4-392, 4-418, 

4-435

Pipelines, xv, xviii, xix, xxii, xxiv, xxvii, xxviii, 1-11, 1-15, 2-26, 2-28, 2-29, 2-31, 2-36, 2-40, 2-42, 

2-44, 2-45, 2-46, 3-3, 3-4, 3-9, 3-15, 3-16, 3-28, 3-29, 3-30, 3-31, 3-33, 3-34, 3-35, 3-38, 3-39, 

3-40, 3-41, 3-42, 3-43, 3-44, 3-45, 3-46, 3-47, 3-63, 3-70, 3-74, 3-77, 3-82, 3-83, 3-84, 3-85, 

3-86, 3-91, 3-96, 3-97, 3-98, 3-99, 3-100, 3-101, 3-102, 3-105, 3-106, 3-109, 3-112, 3-113, 

3-114, 3-115, 3-116, 3-117, 3-118, 3-121, 3-122, 3-123, 3-124, 3-147, 3-148, 3-150, 3-152, 

3-155, 3-158, 3-159, 3-163, 3-170, 3-171, 3-172, 3-174, 3-175, 3-177, 3-180, 3-182, 3-183, 

3-184, 3-195, 3-197, 3-200, 4-6, 4-9, 4-10, 4-11, 4-12, 4-28, 4-33, 4-37, 4-39, 4-43, 4-49, 4-50, 

4-51, 4-56, 4-57, 4-60, 4-62, 4-64, 4-66, 4-67, 4-68, 4-70, 4-72, 4-73, 4-75, 4-81, 4-84, 4-85, 

4-90, 4-91, 4-95, 4-97, 4-109, 4-148, 4-149, 4-162, 4-170, 4-194, 4-195, 4-203, 4-211, 4-213, 

4-215, 4-220, 4-221, 4-253, 4-254, 4-284, 4-295, 4-296, 4-317, 4-332, 4-351, 4-356, 4-360, 

4-362, 4-363, 4-364, 4-365, 4-366, 4-367, 4-368, 4-370, 4-371, 4-378, 4-380, 4-381, 4-382, 

4-383, 4-385, 4-391, 4-398, 4-400, 4-426, 4-436, 4-438, 4-439, 4-440, 4-441

Port Fourchon, 3-82, 3-86, 3-133, 4-58, 4-65, 4-379, 4-380, 4-383

Produced Waters, 2-30, 3-61, 3-62, 3-203, 4-39, 4-67, 4-95, 4-109, 4-134, 4-162, 4-169, 4-170, 

4-176, 4-211, 4-214, 4-437
Keyword Index Keywords-9 

Public Services, 2-31

Recreational Fishing, xv, xvii, xxii, xxvi, 2-32, 2-34, 2-39, 2-44, 3-162, 3-183, 3-192, 4-3, 4-5, 4-68, 

4-145, 4-146, 4-177, 4-189, 4-199, 4-201, 4-216, 4-244, 4-257, 4-258, 4-287, 4-323, 4-324, 

4-328, 4-330, 4-331, 4-332, 4-333, 4-334, 4-335, 4-336, 4-337, 4-341, 4-344, 4-348, 4-350, 

4-352, 4-353, 4-354, 4-355, 4-376, 4-378, 4-386, 4-400, 4-401, 4-439, 4-441, 4-442, 4-443

Recreational Resources, xv, xvii, xxvi, 2-32, 2-34, 2-44, 4-3, 4-5, 4-83, 4-89, 4-213, 4-217, 4-334, 

4-338, 4-339, 4-343, 4-344, 4-347, 4-348, 4-349, 4-350, 4-351, 4-352, 4-353, 4-354, 4-355, 

4-393, 4-400, 4-430, 4-439

Renewable Energy, 1-4, 1-14, 1-17, 3-75, 3-177, 3-178, 3-183, 3-184, 4-375, 4-429, 4-430, 4-442

Resource Estimates, xiv, 1-20, 2-3, 2-8, 2-9, 2-10, 3-4, 3-5, 3-7, 3-112, 3-114, 3-115

Sargassum, xv, xvi, xx, 1-19, 2-32, 2-34, 2-37, 4-3, 4-5, 4-122, 4-123, 4-124, 4-125, 4-126, 4-127, 

4-128, 4-129, 4-130, 4-131, 4-132, 4-133, 4-134, 4-135, 4-136, 4-137, 4-187, 4-189, 4-191, 

4-198, 4-206, 4-223, 4-267, 4-268, 4-270, 4-271, 4-273, 4-274, 4-275, 4-283, 4-286, 4-317, 

4-438, 5-5 

Sea Turtles, ix, xv, xvi, xxiii, xxiv, 2-28, 2-31, 2-32, 2-34, 2-41, 3-91, 3-94, 3-125, 3-145, 3-192, 

3-194, 4-3, 4-56, 4-79, 4-81, 4-127, 4-128, 4-129, 4-131, 4-132, 4-224, 4-227, 4-239, 4-241, 

4-265, 4-266, 4-267, 4-268, 4-269, 4-270, 4-271, 4-272, 4-273, 4-274, 4-275, 4-276, 4-277, 

4-278, 4-279, 4-280, 4-281, 4-282, 4-283, 4-284, 4-285, 4-286, 4-287, 4-288, 4-289, 4-290, 

4-291, 4-292, 4-293, 4-294, 5-5 

Seagrass Communities, 2-24, 3-140, 3-145, 4-50, 4-51, 4-52, 4-54, 4-55, 4-71, 4-73, 4-78, 4-80, 

4-285, 4-286, 4-289

Service Base, 3-46, 3-47, 3-70, 3-75, 3-77, 3-79, 3-82, 3-154, 4-58, 4-66, 4-74, 4-92, 4-372, 4-378, 

4-380, 4-384

Site Clearance, xxvii, xxix, 1-10, 2-28, 2-45, 3-71, 4-371

Smalltooth Sawfish, 4-186

Soft Bottoms, xix, xxi, 2-37, 2-39, 3-160, 3-205, 4-94, 4-111, 4-138, 4-144, 4-161, 4-171, 4-175, 

4-188, 4-195

Stipulation, ix, xii, xiii, xiv, xx, xxi, xxiii, xxv, xxix, 1-11, 1-20, 2-3, 2-4, 2-8, 2-9, 2-11, 2-12, 2-13, 2-14, 

2-16, 2-23, 2-24, 2-25, 2-26, 2-27, 2-38, 2-39, 2-41, 2-43, 3-164, 3-173, 4-9, 4-11, 4-37, 4-50, 

4-74, 4-82, 4-93, 4-95, 4-121, 4-131, 4-137, 4-138, 4-139, 4-142, 4-146, 4-149, 4-150, 4-151, 

4-153, 4-154, 4-155, 4-156, 4-157, 4-158, 4-161, 4-162, 4-163, 4-168, 4-169, 4-171, 4-172, 

4-173, 4-176, 4-177, 4-180, 4-181, 4-182, 4-183, 4-184, 4-218, 4-222, 4-223, 4-225, 4-227, 

4-241, 4-243, 4-245, 4-248, 4-261, 4-264, 4-265, 4-276, 4-278, 4-279, 4-281, 4-289, 4-291, 

4-293, 4-294, 4-296, 4-299, 4-308, 4-310, 4-312, 4-322, 4-337, 4-344, 4-350, 4-353, 4-355, 

4-392, 4-418, 4-435, 4-440
Keywords-10 Gulf of Mexico Multisale EIS

Submerged Vegetation, xviii, 2-36, 4-50, 4-51, 4-52, 4-54, 4-56, 4-60, 4-61, 4-63, 4-68, 4-71, 4-74, 

5-5 

Synthetic-Based Drilling Fluids, 2-30, 3-53, 3-58, 3-59, 3-69, 3-126, 3-127, 4-44, 4-46, 4-136

Topographic Features, xii, xiii, xiv, xv, xvi, xx, xxi, xxix, 2-3, 2-11, 2-12, 2-14, 2-16, 2-23, 2-27, 2-28, 

2-32, 2-34, 2-38, 3-33, 3-46, 4-3, 4-9, 4-11, 4-37, 4-50, 4-74, 4-93, 4-94, 4-121, 4-137, 4-138, 

4-139, 4-140, 4-141, 4-142, 4-143, 4-144, 4-145, 4-146, 4-147, 4-148, 4-149, 4-150, 4-151, 

4-152, 4-153, 4-154, 4-155, 4-156, 4-157, 4-158, 4-161, 4-162, 4-164, 4-168, 4-173, 4-182, 

4-183, 4-188, 4-222, 4-223, 4-228, 4-239, 4-299, 4-308, 4-309, 4-310, 4-312, 4-322, 4-337, 

4-355, 4-392, 4-418, 4-435, 5-5 

Tourism, ix, xix, 2-29, 2-31, 2-36, 2-37, 3-183, 4-73, 4-80, 4-89, 4-213, 4-286, 4-290, 4-334, 4-339, 

4-340, 4-341, 4-345, 4-349, 4-353, 4-355, 4-375, 4-376, 4-429, 4-430, 4-443, 5-8 

Trash, xv, 2-30, 3-68, 3-70, 3-152, 3-163, 3-169, 4-45, 4-47, 4-48, 4-59, 4-67, 4-75, 4-81, 4-82, 4-85, 

4-95, 4-130, 4-131, 4-161, 4-214, 4-216, 4-220, 4-227, 4-244, 4-245, 4-264, 4-278, 4-279, 4-286, 

4-292, 4-293, 4-295, 4-297, 4-298, 4-299, 4-306, 4-343, 4-344, 4-349, 4-350, 4-438, 4-439

Waste Disposal, 3-39, 3-70, 3-75, 3-77, 3-84, 3-165, 4-48, 4-59, 4-64, 4-67, 4-203, 4-372, 4-373, 

4-378, 4-380, 4-381, 4-383, 4-384

Wastes, xxii, xxiv, 2-30, 2-40, 2-42, 3-3, 3-24, 3-53, 3-65, 3-67, 3-68, 3-69, 3-70, 3-84, 3-154, 3-162, 

3-165, 3-166, 3-169, 3-202, 4-6, 4-38, 4-39, 4-43, 4-45, 4-48, 4-51, 4-56, 4-59, 4-76, 4-169, 

4-203, 4-204, 4-211, 4-219, 4-243, 4-256, 4-276, 4-278, 4-289, 4-306, 4-381, 4-383

Water Quality, xv, xvi, xviii, xx, xxiv, 1-19, 2-3, 2-30, 2-32, 2-33, 2-35, 2-38, 2-42, 3-53, 3-54, 3-58, 

3-61, 3-62, 3-71, 3-110, 3-162, 3-164, 3-168, 3-193, 3-204, 4-3, 4-4, 4-37, 4-39, 4-40, 4-41, 

4-42, 4-43, 4-44, 4-45, 4-46, 4-47, 4-48, 4-49, 4-50, 4-55, 4-109, 4-112, 4-124, 4-133, 4-135, 

4-142, 4-170, 4-173, 4-185, 4-197, 4-211, 4-214, 4-215, 4-219, 4-227, 4-243, 4-244, 4-253, 

4-286, 4-288, 4-306, 4-307, 4-352, 4-386, 4-429, 4-437, 4-439, 4-444

Wetlands, ix, xv, xviii, 2-28, 2-29, 2-32, 2-36, 3-42, 3-84, 3-141, 3-181, 3-183, 3-188, 3-189, 3-190, 

3-191, 3-195, 3-196, 3-197, 4-8, 4-41, 4-50, 4-51, 4-52, 4-53, 4-54, 4-56, 4-57, 4-59, 4-60, 4-61, 

4-62, 4-63, 4-64, 4-65, 4-66, 4-67, 4-68, 4-69, 4-70, 4-71, 4-72, 4-73, 4-74, 4-77, 4-78, 4-89, 

4-187, 4-200, 4-203, 4-206, 4-212, 4-213, 4-216, 4-217, 4-218, 4-219, 4-220, 4-300, 4-301, 

4-304, 4-305, 4-307, 4-349, 4-352, 4-374, 4-376, 4-381, 4-430, 4-431, 4-432, 4-438, 4-440, 

4-444, 5-5, 5-7, 5-10

The Department of the Interior Mission

The Department of the Interior protects and manages the Nation’s natural 

resources and cultural heritage; provides scientific and other information 

about those resources; and honors the Nation’s trust responsibilities or 

special commitments to American Indians, Alaska Natives, and affiliated 

island communities.

The Bureau of Ocean Energy Management Mission

The Bureau of Ocean Energy Management (BOEM) is responsible for 

managing development of U.S. Outer Continental Shelf energy and mineral 

resources in an environmentally and economically responsible way.