OCS Study 

BOEMRE 2011-028 

Coastal Marine Institute 

Assessment of Opportunities 

for Alternative Uses of Hydrocarbon 

Infrastructure in the Gulf of Mexico 

Cooperative Agreement

Coastal Marine Institute 

Louisiana State University 

U.S. Department of the Interior

Bureau of Ocean Energy Management, 

 Regulation and Enforcement 

Gulf of Mexico OCS Region 
U.S. Department of the Interior Cooperative Agreement 

Bureau of Ocean Energy Management, Coastal Marine Institute 

 Regulation and Enforcement Louisiana State University 

Gulf of Mexico OCS Region 

OCS Study 

BOEMRE 2011-028 

Coastal Marine Institute 

Assessment of Opportunities 

for Alternative Uses of Hydrocarbon 

Infrastructure in the Gulf of Mexico 

Authors 

Mark J. Kaiser 

Brian Snyder 

Allan G. Pulsipher 

July 2011 

Prepared under BOEMRE Cooperative Agreement 

1435-01-04-CA-32806-39314 (M05AC12278) 

by 

Louisiana State University 

Center for Energy Studies 

Baton Rouge, Louisiana 70803 

Published by 
iii

DISCLAIMER

This report was prepared under contract between the Bureau of Ocean Energy Management, 

Regulation and Enforcement (BOEMRE) and Louisiana State University’s Center for Energy 

Studies. This report has been technically reviewed by the BOEMRE, and it has been approved 

for publication. Approval does not signify that the contents necessarily reflect the views and 

policies of the BOEMRE, nor does mention of trade names or commercial products constitute 

endorsement or recommendation for use. It is, however, exempt from review and compliance 

with the BOEMRE editorial standards. 

REPORT AVAILABILITY 

This report is available only in compact disc format from the Bureau of Ocean Energy 

Management, Regulation and Enforcement, Gulf of Mexico OCS Region, at a charge of $15.00, 

by referencing OCS Study BOEMRE 2011-028. The report may be downloaded from the 

BOEMRE website through the Environmental Studies Program Information System (ESPIS). 

You will be able to obtain this report also from the National Technical Information Service in the 

near future. Here are the addresses. You may also inspect copies at selected Federal Depository 

Libraries. 

 U.S. Department of the Interior U.S. Department of Commerce 

 Bureau of Ocean Energy Management, National Technical Information Service 

 Regulation and Enforcement 5285 Port Royal Road 

 Gulf of Mexico OCS Region Springfield, Virginia 22161 

 Public Information Office (MS 5034) Phone: (703) 605-6040 

 1201 Elmwood Park Boulevard Fax: (703) 605-6900 

 New Orleans, Louisiana 70123-2394 Email: bookstore@ntis.gov

Telephone requests may be placed at 

 (504) 736-2519, 1-800-200-GULF, or 

Rush Orders: 1-800-553-6847 

 Fax: (504) 736-2620 

CITATION 

Kaiser, M.J., B. Snyder, and A.G. Pulsipher. 2011. Assessment of opportunities for alternative 

uses of hydrocarbon infrastructure in the Gulf of Mexico. U.S. Dept. of the Interior, 

Bureau of Ocean Energy Management, Regulation and Enforcement, Gulf of Mexico 

OCS Region, New Orleans, LA. OCS Study BOEMRE 2011-028. 278 pp. 

ABOUT THE COVER 

Sources: Talisman Energy, 2008; National Geographic, 2009; Reggio, 1996. 
v

ABSTRACT

When an operator is granted a lease to develop oil and gas resources on the Outer Continental 

Shelf in the Gulf of Mexico, they are required to remove structures within one year of the end of 

production on the lease. There are approximately 3,507 offshore oil and gas structures in the 

Gulf as of January 2011. Over the next decade, the number of structures is expected to decline 

by about 1,500, thus, there is a great deal of interest among both regulators and operators in 

finding new uses for these structures. Currently, most of the offshore structures that have been 

decommissioned are brought to shore and stored or used for scrap with a small number being 

reused in new developments. Artificial reef programs in Louisiana and Texas accept a modest 

number of platforms. The most likely alternative applications are as bases for mariculture or 

foundations for offshore wind farms. In this report we analyze the relative merits of each of 

these uses and potential uses based on their technological and economic feasibility. In short, 

platform based mariculture, while technically feasible, is plagued by economic issues that make 

it unlikely to be profitable in the near-term, while oil and gas infrastructure is generally not 

suited for the offshore wind industry due to scale economies and several other technical issues. 

It is possible that both mariculture and offshore wind could use oil and gas infrastructure in the 

future, and we discuss the circumstances under which this might occur. We find that only the 

use of platforms as artificial reefs is a realistic near term destination for existing infrastructure. 
vii

TABLE OF CONTENTS

Page

LIST OF FIGURES ...................................................................................................................... xv

LIST OF TABLES....................................................................................................................... xix

EXECUTIVE SUMMARY ............................................................................................................ 1

1. USE OF OFFSHORE PLATFORMS FOR ARTIFICIAL REEFS.......................................... 3

 1.1. National Fishing Enhancement Act.................................................................................. 3 

 1.2. Types of Offshore Facilities ............................................................................................. 4 

 1.3. Stages of Oil and Gas Development................................................................................. 5 

 1.3.1. Produce................................................................................................................... 5 

 1.3.2. Invest/Divest........................................................................................................... 5 

 1.3.3. Abandon ................................................................................................................. 6 

 1.3.4. Decommission ........................................................................................................ 6 

 1.4. Regulatory Requirements ................................................................................................. 6 

 1.4.1. Legislation .............................................................................................................. 7 

 1.4.2. Permit Agencies...................................................................................................... 7 

 1.4.3. Aids to Navigation.................................................................................................. 8 

 1.5. Decommissioning Decision Tree...................................................................................... 8 

 1.6. Stages of Decommissioning ............................................................................................. 9 

 1.6.1. Planning and Permitting ......................................................................................... 9 

 1.6.2. Plug and Abandonment .......................................................................................... 9 

 1.6.3. Preparation............................................................................................................ 10 

 1.6.4. Pipeline Abandonment ......................................................................................... 10 

 1.6.5. Structure Removal................................................................................................ 10 

 1.6.6. Site Clearance and Verification............................................................................ 11 

 1.7. Factor Description .......................................................................................................... 11 

 1.7.1. Complexity ........................................................................................................... 12

 1.7.2. Location................................................................................................................ 12 

 1.7.3. Water Depth.......................................................................................................... 12

 1.7.4. Removal Method .................................................................................................. 13 

 1.7.5. Exogenous Events ................................................................................................ 13 

 1.7.6. Tow Distance........................................................................................................ 13 

 1.7.7. Scale Economics................................................................................................... 13

2. LOUISIANA ARTIFICIAL REEF PROGRAM.................................................................... 15

 2.1. Background..................................................................................................................... 15 

 2.1.1. Donation Requirements ........................................................................................ 15 

 2.1.2. Liability ................................................................................................................ 15 

 2.1.3. Artificial Reef Planning Areas ............................................................................. 16
viii

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Page

 2.2. Descriptive Statistics ...................................................................................................... 16 

 2.2.1. Structure Donation................................................................................................ 16 

 2.2.2. Program Statistics................................................................................................. 16 

 2.2.3. Operator Involvement........................................................................................... 17 

 2.2.4. Capture Probability and Removal Method ........................................................... 17

 2.3. Model Development ....................................................................................................... 18 

 2.3.1. Model Specification.............................................................................................. 18 

 2.3.2. Model Results....................................................................................................... 18 

 2.3.3. Example................................................................................................................ 19

3. TEXAS ARTIFICIAL REEF PROGRAM............................................................................. 21

 3.1. Background..................................................................................................................... 21 

 3.1.1. History .................................................................................................................. 21 

 3.1.2. Liability ................................................................................................................ 21 

 3.1.3. Donation Requirements ........................................................................................ 21 

 3.1.4. Planning Areas...................................................................................................... 22 

 3.2. Descriptive Statistics ...................................................................................................... 22 

 3.2.1. Structure Donation................................................................................................ 22 

 3.2.2. Removal Methods................................................................................................. 23 

 3.2.3. Severance Method ................................................................................................ 23 

 3.2.4. Operator Involvement........................................................................................... 23 

 3.2.5. Capture Probability Statistics ............................................................................... 23 

 3.3. Model Development ....................................................................................................... 24 

 3.3.1. Model Specification.............................................................................................. 24 

 3.3.2. Expected Signs ..................................................................................................... 24 

 3.3.3. Model Results....................................................................................................... 24 

 3.3.4. Example................................................................................................................ 25

4. IMPACT OF THE 2005 HURRICANE SEASON ON THE LOUISIANA ARTIFICIAL 

 REEF PROGRAM.................................................................................................................. 27

 4.1. 2005 Hurricane Season................................................................................................... 27 

 4.2. Decommissioning Hurricane-Destroyed Infrastructure.................................................. 28 

 4.2.1. Well Plugging and Abandonment ........................................................................ 29 

 4.2.2. Structure Removal................................................................................................ 30 

 4.2.3. Site Clearance and Verification............................................................................ 30 

 4.3. LARP Statistics............................................................................................................... 30 

 4.4. SARS Program................................................................................................................ 30 

 4.4.1. Definition.............................................................................................................. 30 

 4.4.2. Selection Criteria.................................................................................................. 31 

 4.4.3. Procedures ............................................................................................................ 31
ix

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Page

 4.5. SARS Program Statistics ................................................................................................ 31

 4.5.1. SARS Approvals 1991-2005 ................................................................................ 31 

 4.5.2. Post-Katrina SARS Approvals ............................................................................. 32 

 4.5.3. RPI Screening Criteria.......................................................................................... 33 

 4.5.4. Notable Applications............................................................................................ 33

 4.6. BOEMRE Policy on Toppled Facilities ......................................................................... 34 

 4.6.1. Engineering, Stability, and Environmental Reviewing Standards ....................... 34 

 4.6.2. Reef-Approval Guidelines.................................................................................... 35 

5. ASSESSMENT OF PLATFORM-BASED MARICULTURE IN THE GULF OF 

 MEXICO................................................................................................................................. 37

 5.1. Open Ocean Aquaculture................................................................................................ 37

 5.2. Regulatory Authority...................................................................................................... 38 

 5.3. Platform Systems............................................................................................................ 38

 5.4. Costs and Benefits of Using Offshore Oil and Gas Platforms........................................ 39 

 5.4.1. Advantages to Mariculturists................................................................................ 39 

 5.4.2. Advantages to Oil and Gas Operators .................................................................. 40 

 5.4.3. Disadvantages to Mariculturists ........................................................................... 40 

 5.4.4. Disadvantages to Oil and Gas Operators.............................................................. 41 

 5.4.5. Ecological Impacts ............................................................................................... 41 

 5.5. Open Ocean Mariculture Projects................................................................................... 42 

 5.6. Platform-Based Mariculture Projects ............................................................................. 43 

 5.6.1. International Platform-Based Projects.................................................................. 43 

 5.6.2. Texas Sea Grant Project ....................................................................................... 44 

 5.6.3. SeaFish Mariculture LLC..................................................................................... 44 

 5.6.4. Gulf of Mexico Offshore Aquaculture Consortium ............................................. 44 

 5.6.5. Grace Platform Project ......................................................................................... 45 

 5.6.6. GMIT Project........................................................................................................ 45 

 5.7. Site Selection .................................................................................................................. 46 

 5.7.1. Topography........................................................................................................... 46

 5.7.2. Water Exchange.................................................................................................... 46 

 5.7.3. Temperature.......................................................................................................... 47

 5.7.4. Salinity.................................................................................................................. 47 

 5.7.5. Oxygen ................................................................................................................. 47 

 5.7.6. Algae Blooms ....................................................................................................... 47 

 5.7.7. Jellyfish Blooms ................................................................................................... 48 

 5.7.8. Hurricanes............................................................................................................. 48 

 5.7.9. User Conflicts....................................................................................................... 48

 5.7.10. Proximity to Markets.......................................................................................... 49 

 5.7.11. Suitable Platforms .............................................................................................. 49 
x

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Page

 5.8. Removal and Reuse of Platforms ................................................................................... 49 

 5.9. Conclusion ...................................................................................................................... 50

6. ECONOMIC FEASIBILITY ASSESSMENT FOR PLATFORM-BASED 

 MARICULTURE IN THE GULF OF MEXICO ................................................................... 51

 6.1. Prior Studies of Offshore Aquaculture Costs ................................................................. 51 

 6.2. Methodology................................................................................................................... 51 

 6.2.1. Model Assumptions.............................................................................................. 52 

 6.2.2. Model A Calculations........................................................................................... 53 

 6.2.3. Model B Calculations ........................................................................................... 53 

 6.3. Results............................................................................................................................. 54 

 6.3.1. Model A Results................................................................................................... 54 

 6.3.2. Model B Results ................................................................................................... 54 

 6.3.3. Rent Scenario........................................................................................................ 54

 6.4. Limitations of This Analysis .......................................................................................... 55 

 6.5. Discussion....................................................................................................................... 56 

 6.6. Conclusions..................................................................................................................... 56

7. COMPARISON OF OFFSHORE WIND POWER DEVELOPMENT IN 

 EUROPE AND THE U.S. ...................................................................................................... 59

 7.1. Introduction..................................................................................................................... 59 

 7.2. Offshore Wind Energy Development in Europe ............................................................ 60 

 7.2.1. European Wind Farms.......................................................................................... 60 

 7.2.2. Trends in Europe .................................................................................................. 60 

 7.2.3. Industry Structure ................................................................................................. 60 

 7.2.4. System Configurations ......................................................................................... 61 

 7.2.5. Installation ............................................................................................................ 61 

 7.2.6. Foundations .......................................................................................................... 62

 7.3. U.S. Development........................................................................................................... 62 

 7.3.1. Cape Wind ............................................................................................................ 63 

 7.3.2. WEST ................................................................................................................... 63 

 7.3.3. Bluewater Wind.................................................................................................... 64 

 7.3.4. Deepwater Wind - Plum Island Wind Park .......................................................... 64 

 7.3.5. LIOWP ................................................................................................................. 64 

 7.3.6. Babcock and Brown - Padre Island Wind Farm................................................... 65 

 7.3.7. South Coast Wind................................................................................................. 65 

 7.3.8. Proposals to BOEMRE......................................................................................... 65 

 7.4. Patterns of Development................................................................................................. 66 

 7.5. Causes of Differences in European and U.S. Industries................................................. 67 

 7.5.1. Financial Incentives and Subsidies....................................................................... 67 

 7.5.2. Regulations........................................................................................................... 69 
xi

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 7.5.3. Wind Resources.................................................................................................... 70 

 7.5.4. Population Density ............................................................................................... 70 

 7.5.5. Commercial Interests............................................................................................ 71

 7.6. Potential Policies for Increasing Offshore Wind in the U.S........................................... 71 

 7.6.1. The Production Tax Credit ................................................................................... 71 

 7.6.2. Greenhouse Gas Legislation................................................................................. 72 

 7.6.3. Renewable Portfolio Standards ............................................................................ 73 

 7.6.4. National Goals for Offshore Wind Power ............................................................ 74 

 7.7. Conclusions..................................................................................................................... 74

8. ECOLOGICAL AND ECONOMIC COST-BENEFIT ANALYSIS OF OFFSHORE 

WIND ENERGY .................................................................................................................... 77

 8.1. Introduction..................................................................................................................... 77 

 8.2. Criticisms of Offshore Wind Power ............................................................................... 77 

 8.2.1. Navigational Safety .............................................................................................. 78 

 8.2.2. Federal Subsidies.................................................................................................. 78 

 8.2.3. Aesthetics ............................................................................................................. 78 

 8.2.4. Cost and Risk........................................................................................................ 79 

 8.2.5. Unpredictable Power............................................................................................ 79

 8.3. Benefits of Offshore Wind Power .................................................................................. 79 

 8.3.1. Location................................................................................................................ 80 

 8.3.2. Power.................................................................................................................... 80 

 8.3.3. Transport and Construction .................................................................................. 80 

 8.3.4. Design Considerations.......................................................................................... 81 

 8.4. Cost Estimates of Wind Power....................................................................................... 81 

 8.4.1. Costs of Onshore Wind Power ............................................................................. 82 

 8.4.2. Offshore Cost Estimates ....................................................................................... 82 

 8.4.3. Cost Components.................................................................................................. 83 

 8.5. Offshore Cost Functions................................................................................................. 83 

 8.5.1. Data Source .......................................................................................................... 83 

 8.5.2. Model Specification.............................................................................................. 83 

 8.5.3. Model Results....................................................................................................... 85 

 8.5.4. Limitations of Analysis ........................................................................................ 85 

 8.6. Managing Costs .............................................................................................................. 85 

 8.6.1. Factors Influencing Revenue................................................................................ 85 

 8.6.2. Site Selection Impacts .......................................................................................... 86 

 8.6.3. Project Specific Impacts ....................................................................................... 87 

 8.6.4. Economies of Scale .............................................................................................. 87 

 8.6.5. Technological Learning........................................................................................ 88 

 8.7. Environmental Impacts of Offshore Wind Power .......................................................... 88 

 8.7.1. Impacts on Birds................................................................................................... 88 
xii

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Page

 8.7.2. Impacts on Marine Mammals............................................................................... 89 

 8.7.3. Impacts on Fish..................................................................................................... 90 

 8.7.4. Environmental Benefits of Offshore Wind Power ............................................... 91

 8.8. Ecological Mitigation ..................................................................................................... 93 

 8.8.1. Mitigation through Site Selection......................................................................... 93 

 8.8.2. Mitigation through Technology............................................................................ 94 

 8.9. Conclusion ...................................................................................................................... 95

9. REVIEW OF OFFSHORE WIND POWER REGULATORY ISSUES ................................ 97

 9.1. Introduction..................................................................................................................... 97 

 9.2. Regulatory Systems in Europe........................................................................................ 98 

 9.2.1. United Kingdom ................................................................................................... 98 

 9.2.2. Denmark ............................................................................................................. 100

 9.2.3. The Netherlands.................................................................................................. 101 

 9.2.4. Germany ............................................................................................................. 102

 9.3. U.S. Programs............................................................................................................... 103 

 9.3.1. BLM Guidelines ................................................................................................. 103 

 9.3.2. Texas Offshore Wind Program........................................................................... 104 

 9.4. BOEMRE Regulations.................................................................................................. 105 

 9.4.1. Lease Terms........................................................................................................ 105 

 9.4.2. Competition and Approval Criteria.................................................................... 106

 9.4.3. Environmental Analysis ..................................................................................... 107 

 9.4.4. Operation ............................................................................................................ 107 

 9.4.5. Decommissioning ............................................................................................... 107

 9.4.6. Supplemental Bonding ....................................................................................... 107 

 9.5. Regulatory Issues.......................................................................................................... 108 

 9.5.1. Lease Terms........................................................................................................ 108 

 9.5.2. Competition and Approval Criteria.................................................................... 111 

 9.5.3. Environmental Analyses..................................................................................... 112 

 9.5.4. Operational Issues .............................................................................................. 113 

 9.5.5. Decommissioning ............................................................................................... 114 

 9.6. Conclusion .................................................................................................................... 116

10. COMMENTARY ON THE USE OF OFFSHORE OIL AND GAS 

INFRASTRUCTURE IN WIND ENERGY APPLICATIONS ........................................... 117

 10.1. Introduction................................................................................................................. 117 

 10.2. Benefits....................................................................................................................... 118 

 10.2.1. Delaying Decommissioning Costs ................................................................... 118 

 10.2.2. Foundation Costs.............................................................................................. 118 

 10.2.3. Marine Habitat.................................................................................................. 118 

 10.2.4. Visual Benefits ................................................................................................. 119 
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 10.3. Difficulties .................................................................................................................. 119 

 10.3.1. Economies of Scale .......................................................................................... 119 

 10.3.2. Location............................................................................................................ 119 

10.3.3. Configuration.................................................................................................... 120 

 10.3.4. Engineering Requirements ............................................................................... 120 

 10.4. Alternative Offshore Uses .......................................................................................... 120 

 10.4.1. Intra-Field Use.................................................................................................. 120 

 10.4.2. Small Scale Use................................................................................................ 121 

 10.4.3. Electrical Service Platforms ............................................................................. 121 

 10.4.4. Electrically Connected Platforms ..................................................................... 122 

 10.4.5. Resource Evaluation or Technology Testing ................................................... 122 

 10.5. Factors Influencing Utilization................................................................................... 122 

 10.6. Conclusion .................................................................................................................. 123

REFERENCES ........................................................................................................................... 125

GLOSSARY OF ABBREVIATIONS ........................................................................................ 151

APPENDIX A. CHAPTER 1 TABLES AND FIGURES .......................................................... 153

APPENDIX B. CHAPTER 2 TABLES AND FIGURES .......................................................... 171

APPENDIX C. CHAPTER 3 TABLES AND FIGURES .......................................................... 179

APPENDIX D. CHAPTER 4 TABLES AND FIGURES .......................................................... 187

APPENDIX E. CHAPTER 5 TABLES AND FIGURES........................................................... 199

APPENDIX F. CHAPTER 6 TABLES AND FIGURES........................................................... 211

APPENDIX G. CHAPTER 7 TABLES AND FIGURES .......................................................... 227

APPENDIX H. CHAPTER 8 TABLES AND FIGURES .......................................................... 267

APPENDIX I. CHAPTER 9 TABLES AND FIGURES............................................................ 277
xv

LIST OF FIGURES

Page

Figure A.1. Structures Removed in the Outer Continental Shelf of the Gulf of 

 Mexico (1973-2003). .......................................................................................... 156 

Figure A.2. Cumulative Number of Structures Removed in the GOM (1973-2006)............. 156 

Figure A.3. Caisson Structures............................................................................................... 157 

Figure A.4. Well Protector and Fixed Platform Structures.................................................... 158 

Figure A.5. Subsea Equipment and Configuration ................................................................ 159 

Figure A.6. Deepwater Development Strategies.................................................................... 160 

Figure A.7. Federal Outer Continental Shelf Leasing Program............................................. 161 

Figure A.8. Offshore Oil and Gas Facility Decommissioning Tree....................................... 162 

Figure A.9. Derrick Barge Arrives On-Site and Removes the Deck Module........................ 163 

Figure A.10. Explosives Technicians Prepare and Load Charges into Conductors 

 and Legs.............................................................................................................. 163 

Figure A.11. Aerial View of Job Site during Blast and Detonation......................................... 164 

Figure A.12. Severed Piles and Conductors Loaded onto Derrick Barge................................ 164 

Figure A.13. Jacket Lifted from Water .................................................................................... 165 

Figure A.14. Jacket and Deck Transported to Shore or Artificial Reef Site............................ 166 

Figure A.15. Structure Toppled-in-Place ................................................................................. 167 

Figure A.16. Platform Removal Methods ................................................................................ 168 

Figure A.17. Gorilla Net Application....................................................................................... 169 

Figure B.1. Louisiana Artificial Reef Program Designated Planning Areas ......................... 178 

Figure C.1. Texas Artificial Reef Sites and High Island General Planning Area.................. 186 

Figure D.1. Hurricane Katrina and Rita Tracks Relative to Offshore Oil and Gas 

 Infrastructure....................................................................................................... 192 

Figure D.2. Structures Destroyed in Hurricanes Ivan, Katrina, and Rita............................... 193 

Figure D.3. Before and After - Devon Energy’s SA-1 Platform 

 Destroyed at South Marsh 128............................................................................ 194 

Figure D.4. Before and After - BT Operating Company Platform 

 Destroyed at Eugene Island 294A....................................................................... 195 

Figure D.5. Model Rendition of Hurricane Destroyed Structure Lying Horizontally 

 on the Seafloor .................................................................................................... 196 

Figure D.6. Model Rendition of Hurricane Destroyed Structure Lying Horizontally 

 on the Seafloor .................................................................................................... 197 

Figure D.7. Louisiana Special Artificial Reef Sites 1991-2005 and Approved in 

 2006..................................................................................................................... 198 

Figure E.1. Artist Conception of Platform-Based Mariculture Operation............................. 203 

Figure E.2. Net-Pen and Submerge Cage .............................................................................. 204 

Figure E.3. Distribution of Existing Fixed Platforms by Depth (2008) ................................ 205 

Figure E.4. Extent of the GOM Hypoxia Zone in 2007 ........................................................ 206 

Figure E.5. Paths of Major Hurricanes Impacting the Gulf Coast from 1983 to 2004.......... 207 

Figure E.6. Distribution of Platforms by Age........................................................................ 208 

Figure E.7. Ship Traffic Lanes and Fixed Platforms ............................................................. 209
xvi

LIST OF FIGURES 

(continued) 

Page

Figure E.8. Preferred Platforms for Use in OOA with 25 and 50 m Contours...................... 210 

Figure F.1. Sensitivity of NPV to Changes in Contingency Capital Cost, Cost of 

 Capital, and Initial Stocking Density.................................................................. 223 

Figure F.2. Relationship Between Stocking Density and FCR in Model B, Expected 

 Scenario............................................................................................................... 224 

Figure F.3. NPV Break-Even Relationship Between Stocking Density and Growth 

 Rate in Model B, Expected Scenario .................................................................. 225 

Figure F.4. NPV Break-Even Relationship Between Stocking Density and Survival 

 Rate in Model B, Expected Scenario .................................................................. 226 

Figure G.1. Cumulative Capacity of the U.S. and European Onshore Wind Industry .......... 236 

Figure G.2. Cumulative Capacity of European Offshore Wind Farms.................................. 237 

Figure G.3. Operational and Planned Offshore Wind Farms as of 2007 ............................... 238 

Figure G.4. Increasing Size of Development of European Offshore Wind Farms 

 Over Time ........................................................................................................... 239 

Figure G.5. Increasing Depth of European Offshore Wind Farms Over Time...................... 240 

Figure G.6. Increasing Turbine Capacity of European Offshore Wind Farms Over 

 Time .................................................................................................................... 241 

Figure G.7. Increasing Distance to Shore of European Offshore Wind Farms Over 

 Time .................................................................................................................... 242 

Figure G.8a. Rows of Turbines at Nysted with Sailboat in Foreground.................................. 243 

Figure G.8b. Row of Turbines at North Hoyle Showing Transition Piece Painted 

 Yellow for Navigational Purposes...................................................................... 244 

Figure G.8c. Grid Arrangement of Horns Rev Wind Farm ..................................................... 245 

Figure G.8d. Aerial View of Kentish Flats .............................................................................. 246 

Figure G.8e. Burbo Bank Offshore Wind Farm....................................................................... 247 

Figure G.8f. Scroby Sands....................................................................................................... 248 

Figure G.9. Middlegrunden Offshore Wind Farm Showing Curved Arrangement ............... 249 

Figure G.10. Layout of Horns Rev II Wind Farm.................................................................... 250 

Figure G.11. Electrical Service Platform at Lillgrund ............................................................. 251 

Figure G.12. Monopile after Installation by Jack-Up Barge Resolution at Kentish 

 Flats..................................................................................................................... 252 

Figure G.13. Nacelle and Blades Being Lifted In Bunny Ear Configuration at 

 Kentish Flats ....................................................................................................... 253 

Figure G.14. Beatrice Jacket Foundation................................................................................. 254 

Figure G.15. Sinking of a Jacketed Foundation for the Beatrice Project................................. 255 

Figure G.16. Lifting of the Beatrice Turbine and Foundation ................................................. 256 

Figure G.17. Connection of the Beatrice Turbine Tower and Foundation .............................. 257 

Figure G.18. Gravity Foundations at Nysted ........................................................................... 258 

Figure G.19. Monopile for Use at Kentish Flats...................................................................... 259 

Figure G.20. Approximate Location of Cape Wind Offshore Wind Farm .............................. 260 

Figure G.21. Annual Average of World Offshore Wind Resources ........................................ 261 

Figure G.22. Wind Speeds in Europe....................................................................................... 262
xvii

LIST OF FIGURES 

(continued) 

Page

Figure G.23. Wind Speeds in the U.S. ..................................................................................... 263 

Figure G.24. Population Density of Europe............................................................................. 264 

Figure G.25. Population Density of the U.S. ........................................................................... 265 

Figure H.1. Costs of Onshore and Offshore Wind................................................................. 274 

Figure H.2. Capital Costs Versus Turbine Size ..................................................................... 275 

Figure H.3. Capital Costs as a Function of Wind Farm Size ................................................. 275 

Figure I.1. Flow Chart of Texas Regulatory Process............................................................ 281 

Figure I.2. Flow Chart of BLM Regulatory Process ............................................................ 282 
xix

LIST OF TABLES

Page

Table A.1. Structure Inventory in the Gulf of Mexico (2003).............................................. 155 

Table A.2. Deepwater Production Facilities Installed in the Gulf of Mexico, 

 Including Plans Through 2006............................................................................ 155 

Table B.1. Louisiana Artificial Reef Planning Areas........................................................... 173

Table B.2. Louisiana Artificial Reef Program Structure Donations (1987-2003)................ 173 

Table B.3. Louisiana Artificial Reef Program Statistics (1987-2003) ................................. 174 

Table B.4. Operator Donation (1987-2003) ......................................................................... 175 

Table B.5. Structures Removed and Reefed in the Central Gulf of Mexico (1987- 

 2002) ................................................................................................................... 176 

Table B.6. LARP Donation Model Results – I..................................................................... 176 

Table B.7. LARP Donation Model Results – II.................................................................... 177 

Table B.8. LARP Donation Model Results – III .................................................................. 177 

Table C.1. Texas Artificial Reef Program Platform Donations (1990-2003)....................... 181 

Table C.2. Texas Artificial Reef Program Statistics (1990-2003)........................................ 182 

Table C.3. Top 5 Operator Donations to TARP ................................................................... 183 

Table C.4. Removed and Reefed Structures in the Western Gulf of Mexico (1990- 

 2002) ................................................................................................................... 183 

Table C.5. TARP Donation Model Results – I..................................................................... 184 

Table C.6. TARP Donation Model Results – II.................................................................... 184 

Table C.7. TARP Donation Model Results – III .................................................................. 185 

Table D.1. Structure and Rig Damage Caused by Hurricanes Ivan, Katrina, and 

 Rita...................................................................................................................... 189 

Table D.2. Louisiana Artificial Reef Program Structure Donations (1987-2006)................ 189 

Table D.3. Special Artificial Reef Site Projects and Platform Additions............................. 190 

Table D.4. Special Artificial Reef Sites Approved in 2006.................................................. 191 

Table E.1. Advantages and Disadvantages of Different Logistical Options for 

 Open Ocean Mariculture..................................................................................... 201 

Table E.2. Summary of Platform-Based Mariculture Projects in the United States ............ 202 

Table E.3. Projected Sales and Revenues for GMIT Project (million $) ............................. 202 

Table F.1. Inflation Adjusted Cost Estimates for Offshore Mariculture.............................. 213 

Table F.2. Assumptions of Theoretical Cost Studies of OOA............................................. 214 

Table F.3. Summary of Basic Assumptions......................................................................... 215 

Table F.4. Fish Feed Prices of Top 3 Suppliers in 2007 ...................................................... 216 

Table F.5. Cage Cost Estimate (2007) ................................................................................. 216 

Table F.6. Calculation for Fingerling and Feed Model A.................................................... 217 

Table F.7 Capital Costs for Models A and B ($1,000) ....................................................... 218 

Table F.8. Average Operating Costs Over 10-Year Project Lifetime ($1,000) ................... 219 

Table F.9. Net Present Value Results, Model A .................................................................. 220 

Table F.10. Net Present Value Results, Model B................................................................... 220 

Table F.11. Comparison of Financial Performances of Expected Scenario (Model A) 

 and Rent Scenario ($1,000)................................................................................. 220
xx

LIST OF TABLES 

(continued) 

Page

Table F.12. Break-Even Analysis Showing the Value for Parameters at Which NPV 

 Is Zero ................................................................................................................. 221 

Table F.13. Sensitivity Analysis of Model B, Expected Case ............................................... 222 

Table G.1. Operational Commercial Offshore Wind Farms in Europe as of August 

 2008..................................................................................................................... 229 

Table G.2. Approved Offshore Wind Farms in Europe as of May 2008.............................. 230 

Table G.3. Distribution of Offshore Wind Farms by Country as of August 2008................ 232

Table G.4. Proposed Offshore Wind Projects in the U.S. as of August 2008 ...................... 233 

Table G.5. Economic Incentives for Offshore Wind Development in Europe..................... 234 

Table G.6. Regulations for Leasing Land for Offshore Wind Development in 

 Europe and the U.S. ............................................................................................ 235 

Table G.7. Ten Largest Manufacturers of Turbines in 2006 ................................................ 235 

Table H.1. Summary of Arguments for and Against Offshore Wind and Comparison 

 to Onshore Wind................................................................................................. 269 

Table H.2. Capital Costs and Cost of Energy of Offshore Wind Farms............................... 270 

Table H.3. Costs of Offshore Wind Farms in Europe........................................................... 271 

Table H.4. Parameter Estimates from the Three Best Models from Multiple 

 Regressions ......................................................................................................... 272 

Table H.5. Environmental Impacts Associated with Cape Wind Development 

 According to the EIS........................................................................................... 273 

Table I.1. Major Lease Terms and Components for Selected Offshore Wind 

 Regulatory Authorities........................................................................................ 279 

Table I.2. Texas Royalty System......................................................................................... 280 
1

EXECUTIVE SUMMARY

When an operator is granted a lease to develop oil and gas resources on the Outer Continental 

Shelf of the Gulf of Mexico (GOM), they are required to decommission the lease area within one 

year of the end of production on the lease. Decommissioning involves plugging wells, removing 

structures, and clearing the seafloor of oil and gas debris. Decommissioning represents a liability 

to operators and there are often financial benefits for operators to delay decommissioning. As a 

result, there are several hundred idle structures in the GOM, and the Bureau of Ocean Energy 

Management, Regulation and Enforcement (BOEMRE) has in a recent notice to lessees proposed 

new regulations on plugging and abandonment and structure removal to require operators to 

remove structures as they become economically unviable, rather than when the entire lease area 

stops producing. 

There are approximately 3,507 offshore oil and gas structures in the GOM as of January 2011, 

and over the next decade, about 1,500 structures in the GOM are expected to be removed. 

Approximately 3,450 structures have been removed since 1973. 

The Energy Policy Act of 2005 gave BOEMRE the authority to regulate the use of oil and gas 

structures for alternative marine and energy applications. Thus, there is a great deal of interest in 

finding new uses for oil and gas infrastructure. Currently, most of the offshore structures that 

have been decommissioned are brought to shore and used for scrap with a small number being 

reused in future applications. The most likely alternative applications for this infrastructure are 

as bases for offshore mariculture or as foundations for wind turbines. Additionally, oil and gas 

infrastructure can be and has been, donated to coastal states for use in artificial reef programs. 

It is possible that mariculture operators or offshore wind development could turn uneconomic 

platforms into an asset rather than a liability and may make for their more efficient re-use or 

removal. It is also possible that their use may make other industries, for example the offshore 

wind industry, more profitable by providing a plentiful supply of infrastructure, thereby lowering 

capital costs. 

 

Of the alternative uses for oil and gas infrastructure, only their use as artificial reefs is likely to 

provide an economically attractive outlet for infrastructure in the future. Several hundred oil and 

gas platforms have already been donated as artificial reefs to Texas and Louisiana, and although 

all of the GOM coastal states have active artificial reef programs, not all Gulf states accept 

platforms. 

The prospects for using oil and gas platforms for offshore mariculture operations are limited. 

Platform-based mariculture is an operation in which high-value fish are raised in net cages in 

close proximity to a manned offshore platform. The platforms are used as living and storage 

space and as a base of operations for the culture of the fish. Offshore oil and gas structures 

would make suitable platforms for offshore mariculture operations; however, the high risks, high 

capital and labor costs, and competition from capture fisheries make platform-based offshore 

mariculture a risky and likely unprofitable venture. Therefore, offshore mariculture is unlikely 

to be a significant market for oil and gas platforms unless significant changes in market 

conditions occur. If the price of certain species of wild-caught fish increases, the price of 
2

transporting fish from Asia increases, or the technology for offshore mariculture develops 

further, then the offshore mariculture industry in the U.S. may develop and provide a market for 

some platforms. 

Offshore wind power provides a potential alternative use for oil and gas infrastructure. Offshore 

wind power also faces economic hurdles that are likely to impede the development of the 

industry, and there are basic difficulties in using oil and gas infrastructure in the offshore wind 

industry. Offshore wind farms need to be sited carefully; therefore, oil and gas platforms could 

not be used in place and would need to be moved to new locations; this would eliminate much of 

the cost associated with decommissioning, but could still create a market for jacketed 

foundations. However, offshore wind farms also need to be composed of dozens of wind 

turbines with specific site and operational conditions that require an assembly-line approach for 

foundation placement and turbine installation. This would require developers to collect dozens 

of similar jackets, store them onshore, and then install at a later date. 

We first review decommissioning and artificial reef programs in Louisiana and Texas. We then 

describe the impacts of the 2005 hurricane season on the Louisiana Artificial Reef Program. We 

discuss the platform-based mariculture industry and model its economic profitability through net 

present value analysis. We offer a discussion of offshore wind power, including a comparison of 

its development in the U.S. and Europe, an overview of its costs and benefits, and a discussion of 

the tradeoffs associated with its regulation. The report concludes with a non-technical 

commentary on the problems and potentials of using oil and gas infrastructure in the wind 

industry. 

 
3

1. USE OF OFFSHORE PLATFORMS FOR ARTIFICIAL REEFS 

In this chapter, we provide background information for understanding this practice. We begin by 

describing the types of offshore production facilities and their lifecycle. We outline the 

regulatory environment surrounding decommissioning and discuss the decision matrix governing 

abandonment and the process of decommissioning. We conclude by describing the factors 

governing the costs of decommissioning. 

1.1. National Fishing Enhancement Act 

Offshore platforms have been an important component of both the recreational and fishing 

industries in the Gulf of Mexico (GOM) and have long been recognized as de facto artificial 

reefs (Dauterive, 2001; Harville, 1983; Reggio, 1989). Shortly after an offshore structure is 

installed, sessile invertebrates such as barnacles, oysters, mussels, and sponges attach to the 

underwater frame, attracting mobile invertebrates and fish species, which in turn attract larger 

fish that feed upon them, and so on, forming a highly complex and interrelated food web. Once 

an offshore structure is removed to shore, however, the artificial reef habitat is eliminated and 

the associated biological community is affected. Various platform faunal studies have been 

performed over the years (e.g., Driessen, 1985; Stanley and Wilson, 1991; Carr and Hixon, 

1997), but it is still a matter of scientific debate the degree to which artificial reefs attract and 

produce fishery resources. For a good review of the “attraction versus production” debate, see 

(Pickering and Whitmarsh, 1997). 

Since 1947, when offshore production in the GOM first began, over 2,200 structures have been 

removed (Figures A.1 and A.2). Over the past decade, 141 structures per year on average have 

been removed. As the number of removals began to escalate in the mid-1980s, the need to 

preserve the diverse ecosystems created by the offshore structures became evident (Dauterive, 

2001; Reggio, 1987; Reggio, 1989). 

The first major attempt by the U.S. government to create an artificial reef program was 

undertaken in 1972 when the Department of Commerce authorized the release and sinking of 

World War II Liberty ships for the construction of artificial reefs. The first offshore structure 

reefed in the GOM occurred in 1979, when a 2,120 ton subsea production system was towed 

from Louisiana to a site off western Florida. Over the next few years, several additional 

structures were moved to various sites across the Gulf. Responding to this new activity, Congress 

passed the National Fishing Enhancement Act (NFEA), and in 1984, the NFEA (Title II of 

Public Law 98-623) was signed by President Reagan to “promote and facilitate responsible and 

effective efforts to establish artificial reefs... constructed or placed for the purpose of enhancing 

fishery resources and commercial and recreational opportunities.” 

The NFEA consolidated several decades of local and state laws (Meier, 1989; Murray, 1994; 

Stone, 1985) and directed the National Marine Fisheries Service to develop the National 

Artificial Reef Plan to serve as a guide to state artificial reef programs. The NFEA mandated the 

Secretary of Commerce and other support groups to develop a long-term plan for siting, 

constructing, permitting, installing, monitoring, managing, and maintaining artificial reefs within 

and seaward of state jurisdictions. 
4

1.2. Types of Offshore Facilities 

In the federally1

 regulated Outer Continental Shelf (OCS) of the GOM, nearly 4,000 structures 

are currently in use in the production of oil and natural gas. The types of structures and range of 

configurations vary widely, but shallow-water structures – defined as structures in water depth 

less than 1,000 ft – generally consist of three main elements: 

1) A tubular steel structure, called the template or jacket, which extends from the 

seafloor to above the waterline and is used to support the deck and topsides 

equipment; 

2) Steel pipe piling driven through the jacket legs into the seafloor to provide the 

platform foundation; and 

3) One or more deck sections placed on top of the jacket to hold the drilling and 

processing equipment, heliport, quarters, and related infrastructure. 

In addition to these three basic elements, offshore structures may also contain, depending on the 

function of the structure, 

4) Conductors, which are used to conduct the oil and gas to the surface; 

5) Topsides equipment, such as compressors, cranes, drills, heat exchangers, 

meters, power generation units, pumps, separators, scrubbers, tanks, etc.; and 

6) Bottomsides equipment, such as cable, manifolds, pipelines, flowlines, risers, 

umbilicals, wellheads, etc. 

Offshore development strategies vary depending upon the time of development; reserve size; 

proximity to infrastructure; and operating, economic, environmental, and strategic 

considerations. Shallow water developments in the GOM typically employ caissons (Figure 

A.3), well protectors and fixed platforms (Figure A.4), and subsea completions (Figure A.5). 

 

A caisson is a cylindrical or tapered tube enclosing a well conductor and is the minimum 

structure for offshore development of a well. Structures that provide support through a jacket to 

one or more wells with minimal production equipment and facilities are referred to as a well 

protector. Subsea systems include seafloor and surface equipment: seafloor equipment includes 

subsea wells, manifolds, control umbilicals, and flowlines; surface equipment includes the 

control system and other production equipment located on a host platform. Production from 

caissons, well protectors, and subsea completions is sent to processing facilities on a fixed 

platform prior to being transported to shore. Fixed platforms resemble the jacket structure of 

well protectors, but are larger and more robust, self-contained structures that include facilities for 

drilling, production, and combined operations. The distribution of GOM structures according to 

type, water depth, and planning area is shown in Table A.1. 

In the deepwater GOM defined as water depth greater than 1,000 feet, compliant towers, spars, 

subsea systems, tension-leg platforms, and floating production units are employed (Figure A.6). 

 

1

 The federally regulated waters of the GOM begins seaward three nautical miles offshore the Louisiana, Alabama, 

and Mississippi shorelines, and nine nautical miles from the Texas and Florida shorelines, and extends 200 miles 

through the Exclusive Economic Zone. 
5

The number of deepwater units is relatively small (Table A.2), but currently contribute more than 

70 percent of the total oil production in the GOM. Fixed platforms have an economic water 

depth limit of about 1,500 ft, while compliant towers are viable for water depths ranging between 

1,000-3,000 ft. Tension leg platforms (TLPs) are frequently used in 1,000-5,000 ft water depths. 

Spars, semisubmersible production units, floating production, storage, and offloading systems, 

and subsea wells are used in water depths ranging up to and beyond 10,000 ft (Baud et al., 2002). 

Structures are installed to produce and process hydrocarbons, and when the time arrives that the 

cost to operate a structure exceeds the income from the hydrocarbons under production, the 

structure exists as a liability instead of an asset and becomes a candidate for divestiture or 

abandonment. When the operating cost of a structure equals the income from production, the 

economic limit is said to be reached, and a decision to abandon the structure and shut-in 

production is made. 

1.3. Stages of Oil and Gas Development 

During the life cycle of a field, and depending upon the prevailing and expected future 

economics, technologic development, strategic objectives, political trends, and contract terms, an 

operator has to make many short-term operational and long-term strategic planning decisions. 

Five primary options exist at any point in time: 

• Produce. Hold the asset, produce, and manage the declining reserves. 

• Invest. Invest in the asset to maintain or increase production. 

• Divest. Sell all or a portion of the working interest ownership. 

• Abandon. Stop production. 

• Decommission. Remove the asset in accord with regulatory requirements. 

1.3.1. Produce

 

Early in the life of a field after the development wells have been drilled, the field is produced 

according to equipment capacity and operating constraints. Capital expenditures decline quickly 

after development is complete, and after the field begins to flow, gross revenues turn positive. 

Once the exploration and development cost of the investment have been borne, the variable costs 

of production are usually fairly small, and the operator needs only to produce to achieve cash 

flow. The cumulative net cash flow breaks even at payout after which the cash flow remains 

positive until such time that additional capital investment is required. 

1.3.2. Invest/Divest 

Investment will alter the production profile and will typically extend the life of the asset. If a 

field requires major new investment such as significant workovers or the introduction of 

secondary techniques to maintain production, the field is likely to be considered a candidate for 

divestiture or abandonment. Operators regularly “carve up” assets and sell or subject them to 

various joint venture/farmout type arrangements throughout the life cycle of the field. This is 

sometimes referred to colorfully as an asset “moving down the food chain.” Companies buy 

producing properties and then implement a comprehensive program to increase production, 
6

typically involving drilling new stepout or infill wells and recompleting existing wells. 

Companies specializing2

 in marginal production focus on operating mature fields in a geographic 

region where they already own infrastructure. Divestment frequently acts to extend lease life, 

recover greater quantities of hydrocarbons, and ultimately, delay the “expected” abandonment of 

the structure. 

1.3.3. Abandon 

Structures are installed to produce hydrocarbons, but at some point in time the cost of operation 

will exceed the income from production, and the structure will exist as a liability instead of an 

asset. When the production revenues of the asset approach the operating costs, the structure will 

be abandoned, and depending on lease conditions and operator preferences, decommissioning 

will follow. When a lease no longer produces paying quantities, the operator has one year to 

remove all the structures on the lease. 

1.3.4. Decommission 

The basic aim of decommissioning is to render all wells safe and remove most, if not all, 

surface/seabed signs of production activity. Decommissioning represents a liability as opposed 

to an investment, and so the pressure for an operator to decommission a structure is not nearly as 

strongly driven as installation activities. Delaying decommissioning frequently has economic 

value for the firm since it defers expenditure, while allowing the deferred funds to be invested in 

productive (profit-generating) activities. Federal regulations require that all wells and offshore 

structures on a lease be completely removed within one year after production on the lease ceases. 

Simple structures in shallow waters can be removed relatively easily and inexpensively. 

Caissons are just big pipes in the ground, and so a lift vessel or stiffleg in conjunction with a 

diving crew is usually sufficient to cut it, pull it, and put it on a cargo barge. Braced caissons, 

well protectors, and fixed platforms are more complex structures that require greater planning 

and preparation to ensure the health and safety of workers while minimizing the environmental 

impact and operational cost of removal. Generally speaking, as the structure size, complexity, 

and water depth increases, the removal process becomes more complex and costly, creating 

greater risks to the safety of workers and incurring additional costs to the operator. 

1.4. Regulatory Requirements 

The federal waters of the GOM are divided into three large planning areas labeled the Western, 

Central, and Eastern Gulf of Mexico (Figure A.7). Each planning area is subdivided into smaller 

area codes called area blocks, which in turn are divided into numbered blocks. A block is 

normally a nine square mile area consisting of 5,760 acres and is the smallest unit that can be 

leased for oil and gas exploration. Lease terms and dimensions vary with the time of the auction 

and the location of the lease, but most give the leaseholder the exclusive right to explore for oil 

 

2

 Operators can manage marginal assets at a profit in part due to their lower overheads, lower expected rate of 

return, scale economies, and other strategic factors; e.g., the operator may be a subsidiary of a construction company 

which serves to feed abandoned structures to the parent for removal. 
7

and gas for a period of 5, 8 or 10 years depending on water depth. The terms of the lease extend 

for as long as the lease is productive or development/drilling activities are progressing. 

Different government bodies regulate the decommissioning and abandonment of offshore 

structures, and the regulatory body with primary responsibility is dependent on the physical 

location of the structure. State agencies are responsible for structures located in state waters, 

while the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) is 

responsible for structures in federal waters. The general requirements for decommissioning in 

federal waters are specified in 30 CFR §250.1703 (Federal Register, 2002) and require that all 

wells be permanently plugged and abandoned, all platforms and other facilities be removed, and 

the seafloor cleared of all obstructions created by the operations within one year after the lease or 

pipelines right-of-way terminates. Typically, a lease terminates when production on the lease 

ceases, but special approval may be granted to maintain structures on a non-producing lease. 

1.4.1. Legislation 

All five coastal states bordering the Gulf of Mexico have active artificial reef programs, but only 

Louisiana and Texas rely almost exclusively on oil and gas structures for reef material. Since the 

inception of the Louisiana and Texas Artificial Reef programs (Wilson and Van Sickle, 1987; 

Shively et al., 2003; Stephan, 1996), nearly 200 offshore structures have been accepted as 

artificial reefs. Alabama, Florida, and Mississippi also have prolific reef programs, but have 

accepted far fewer offshore structures because most of the Gulf’s oil and gas infrastructure lie 

offshore Louisiana’s coast in the Central GOM (recall Table A.1). A handful of structures lie 

east of the Mississippi river in waters off Mississippi and Alabama, and a few hundred are 

scattered off the Texas coast. The geographic concentration of platforms means that most 

structures will be towed to the nearest port or scrap yard, while further offshore, reefing will only 

be economic when a structure is located in close proximity to an artificial reef planning area. 

Onshore communities across Louisiana and Texas are also familiar with oil and gas activities, 

and there is generally more widespread community acceptance3

 for the energy industry and rigsto-reef programs, making placement easier and less acrimonious. 

1.4.2. Permit Agencies 

The BOEMRE requires that within one year of an OCS lease termination, the lessee remove the 

structure and clear the area of obstructions. The BOEMRE will waive these requirements to 

accommodate conversion of a structure to an artificial reef provided that (1) the structure does 

not inhibit future development opportunities, (2) the resulting artificial reef complies with the 

Corps of Engineers permit requirements and procedures outlined in the National Artificial Reef 

Plan, (3) a State fishing management agency accepts liability for the structure, and (4) the 

structure meets all applicable BOEMRE engineering, stability, and environmental reviewing 

standards found in the BOEMRE Rigs-to-Reefs policy addendum. Two agencies are involved in 

issuing permits for artificial reefs in federal waters: the U.S. Army Corps of Engineers (COE) 

and the U.S. Coast Guard (USCG). A permit to site a structure as an artificial reef is granted by 

the COE under Section 10 of the Rivers and Harbors Act of 1899 (33 U.S.C. 403). The COE 

 

3

 Reggio has estimated that 70 percent of all fishing trips off the coast of Louisiana were destined for one or more 

offshore structures (Reggio, 1987). 
8

reviews the operation, inspects the materials, and then issues the appropriate permit or makes 

recommendations to improve the permit application. 

1.4.3. Aids to Navigation 

Local Coast Guard districts are responsible for the safety of vessel traffic in their geographic 

areas and have the authority to dictate aids to navigation for obstacles in the water. Artificial 

reefs are classified as obstructions to navigation and must be marked in accordance with USCG 

District guidelines. In general, three factors determine the marking requirements for artificial 

reefs: (1) Distance from navigation fairways, (2) Diameter of the reef complex, and (3) 

Minimum clearance between the top of the reef structure and the water surface. The Coast Guard 

District Commander determines on a case-by-case basis if markers are required and their type4, 

number, and description (Wilson and Van Sickle, 1987). For example, the 8th Coast Guard 

District, with jurisdiction from western Florida to the Texas-Mexico border, generally requires a 

minimum of 85 ft clearance above the obstruction in order to be exempt from maintaining 

lighting requirements. 

1.5. Decommissioning Decision Tree 

Decisions about when and how a structure is decommissioned involve issues of environmental 

protection, safety, cost, and strategic opportunity. The factors that influence the timing of 

removal as well as the manner in which a structure is disposed are complicated and depend as 

much on the technical requirements and cost as on the preferences established by the contractor 

and the federal regulations (Figure A.8). 

The decision to reef a structure is made within the context of alternative decommissioning 

options. Cost is a primary decision factor. If removal option X is expected to have cost E[C(X)], 

then option A will be preferred to option B if E[C(A)]< E[C(B)], all other things being equal. 

Other factors that play a role in decision making include the expected duration of the operation, 

perceived risk, past experience, and historical relationship between the operator and state. 

Oil and gas processing equipment and piping are sent to shore to be refurbished and reused, 

where possible, sold for scrap, and/or disposed of in an approved landfill. Piling and conductors

are typically broken down and recycled, while opportunities for large scale or wholesale reuse of 

topsides equipment is limited due to the effects of age, corrosion, and changing technical 

standards (Terdre, 2000; Van Voorst, 1999). Material such as braces, bridges, heliports and 

miscellaneous steel are typically stored onshore for reuse and scrap. 

Deck and jacket structures have more options for disposal. The deck and jacket may be scrapped 

onshore, moved to a new location and reinstalled, or converted to an artificial reef. Onshore 

disposal is the most common in the GOM, occurring in about 80 percent of structure removals 

 

4

 General guidelines follow: if the obstacle is greater than 61 m (200 ft) in depth, aids to navigation are not required; 

if the obstacle is from 26-61 m (85-200 ft) in depth, unlighted buoys are required; if the obstacle is from 11 m (35 ft) 

to protruding through the surface, lights or lighted buoys and foghorns are required. 
9

since state rig-to-reef programs were initiated. Decks and jackets are stored5

 onshore in 

fabrication and scrap yards and offshore on producing leases as idle iron (Kaiser and Pulsipher, 

2007a). Most structures will be broken down, sold for scrap, and recycled. Decks are generally 

easier to reuse than jackets, and are also easier/cheaper to scrap because of their configuration, 

but they are rarely used as reef material. Jackets, on the other hand, are ideally suited for 

artificial reefs because of their size, shape, design, and density (Harville, 1983; Reggio, 1987). 

The openness of a jacket structure allows for water circulation and easy mobility for fish, 

attracting not only bottom dwelling fish, but also mid- to top-water dwellers. Steel jackets are 

among the most stable and durable6

 reef material available. 

Artificial reefs are a decommissioning option created within the context of the decommissioning 

process and a number of excellent case studies on rigs-to-reef projects are available; e.g., see 

(Hakam and Thornton, 2000; Kasprzak, 1999; Parker and Henkhaus, 1989; Perry et al., 1998; 

Quigel and Thornton, 1989). For a more comprehensive overview of the technical requirements 

of decommissioning, see (Manago and Williamson, 1997; Pulsipher, 1996; National Research 

Council, 1996), and for a broader discussion of rigs-to-reef program and decommissioning, see 

(Baine, 2001; Dauterive, 2001; Hamzah, 2003; MacDonald, 1994; Pulsipher and Daniel, 2000; 

Reggio, 1989; Schroeder and Love, 2004). 

1.6. Stages of Decommissioning 

 

1.6.1. Planning and Permitting 

The engineering planning phase of decommissioning typically consists of a review of all 

contractual obligations and requirements from lease, operating, production, sales or regulatory 

agreements. A plan is developed for each phase of the project, and the process of surveying the 

market for equipment and vessels is initiated. Engineering personnel are sent to the site to assess 

the work requirements, and the project management team will report on the options available to 

the operator, including the scope of work that needs to be performed and how best to prepare the 

bid. Following project engineering and cost assessment, federal and state regulatory permits for 

well plugging and abandonment, pipeline abandonment, structure removal, and site clearance 

verification must be obtained from the BOEMRE (Manago and Williamson, 1997; Pulsipher, 

1996). 

1.6.2. Plug and Abandonment 

The purpose of plug and abandonment (P&A) is to prevent flow of the formation fluid and 

stabilize the wellbore and its associated annuli until geologic forces can re-establish the natural 

barriers that existed before the well was drilled. P&A isolates hydrocarbon zones, protect 

freshwater aquifers, and prevent migration of formation fluids within the wellbore or the 

seafloor. Isolation of the hydrocarbon-bearing intervals and uncemented annuli is critical to 

 

5

 Only a small percentage of structures in inventory, perhaps 10-20 percent for decks, and less than 10 percent for 

jackets, are refurbished and reused. 

6

 Many manmade reefs have historically utilized “materials of opportunity” such as boxcars, tanks, ships, tires, 

construction rubble, oyster shell, etc. Other than ships, most of these materials have little long-term success because 

they are easily broken up and moved by storms. 
10

successful abandonment. P&A activities essentially involve setting various cement plugs in 

wells to ensure downhole isolation of hydrocarbon zones which prevents the migration of 

formation fluids within the wellbore or to the seafloor. Plugging and abandoning wells may 

occur before, during, or after removal preparation activities are complete – depending on the 

scope of work and contractor requirements – but all wells must be P&A prior to cutting and 

removing the conductors. 

1.6.3. Preparation 

The structure is prepared for removal and an inspection is made to determine the condition of the 

structure and identify potential problems with the salvage. Depending on the water depth, 

inspections are performed using divers or a remotely-operated vehicle. On deck, the crew flushes 

and cleans all piping and equipment that contained hydrocarbons. All modules to be removed 

separately from the deck are cut loose, and the piping, electrical, and instrumentation 

interconnections between modules are cut. Work needed to prepare the modules for lifting is 

also performed. The fluids and agents used to purge and clean the vessel must be disposed by 

pumping them downhole through an injection well or to storage in tanks and onshore disposal in 

accord with BOEMRE regulations. Equipment and other metallic debris are sent onshore to 

recycle or scrap, while non-metallic debris is sent as waste to a landfill. 

1.6.4. Pipeline Abandonment 

A pipeline may be abandoned in place if it does not constitute a hazard to navigation, 

commercial fishing operations, or unduly interferes with other users in the OCS. Pipelines 

abandoned in place need to be flushed, filled with seawater, cut, and plugged with the ends 

buried at least 3 ft (1 m) below the mudline. Most pipelines in the GOM are abandoned in place 

and very few complete removals have been performed (Pulsipher, 1996). 

1.6.5. Structure Removal 

The removal of the topside facilities, deck, conductors, piles, and jacket is the core of the 

decommissioning project and typically the most expensive stage (Kaiser et al., 2003). 

Deck Removal 

The deck is normally cut from the jacket using torches. The deck is then lifted and placed on a 

cargo barge (Figure A.9), secured, and returned to shore for scrap or reuse. The interior of the 

piling is then cleared using water jets to remove the mud from within the platform legs so that 

the explosives (or other cutting device) can be lowered 15 feet (5 m) below the mudline. 

Pile and Conductor Removal 

Conductors, casing string, and piling are cut at least 15 ft (5 m) below the mudline, pulled, and 

removed. Conductor severing and removal may take place as part of P&A activity or during the 

structure removal operation. Mechanical casing cutters, abrasive water jets, or explosives are 

used to cut conductors at the designated elevation (Kaiser et al., 2004). Piles are frequently 
11

severed using explosives, although abrasive water jet technology is also employed up to 250 ft. 

The explosives technician prepares and loads the charges into the legs and conductors (Figure 

A.10), the derrick barge is backed off a safe distance, and the explosives are detonated in accord 

with federal regulations (Figure A.11). Piling and conductors are pulled using the derrick barge 

crane (Figure A.12). 

Jacket Removal 

After the conductors and piles have been removed, the jacket structure is lifted out of the water 

(Figure A.13) and welded to a materials barge for transport to shore or a reef site (Figure A.14). 

The jacket can also be floated and towed to a reef site. If the jacket is to be reefed, several 

options are available. In some cases, the jacket is toppled-in-place after the piling has been cut 

(Figure A.15), while in other cases, the jacket is cut in half in the water column and the top-half 

of the structure is placed on the seabed near the bottom half (Figure A.16). A structure “toppledin-place” proceeds much like a complete removal, except that after the piles are cut and removed 

the structure is pulled over and placed on its side on the seafloor. In a “partial removal,” the 

bottom-half of the structure is left standing vertically in the water column while the top-half 

section of the jacket is severed7

 and placed next to the base or removed to shore. 

1.6.6. Site Clearance and Verification 

The last stage in decommissioning is site clearance and verification. Site clearance is the process 

of eliminating, or otherwise addressing, potentially adverse impacts from debris and seafloor 

disturbances, while verification is used to ensure that the site is clear of obstructions. According 

to BOEMRE regulations, all abandoned well and platform locations in water depth less than 300 

feet must be cleared of all obstructions present as a result of oil and gas activities. After the 

jacket has been removed, the site is cleared with a trawling vessel or divers deployed with 

scanning sonar, and then clearance is verified with a trawler. Specialized, heavy-duty trawling 

gears with reinforced mesh, commonly known as “Gorilla Nets,” are used in the operation. The 

nets are dragged over the seafloor in four directions to provide 100 percent coverage of the area 

(Figure A.17). Waivers for site clearance and verification are sometimes granted for structures 

reefed in place. 

1.7. Factor Description 

If a structure is proposed for reefing, an estimate of the costs of alternative decommissioning 

options (reefing, scrapping, etc.) is made before decommissioning is performed and a cost 

savings to the operator from reefing is determined. The operator then generally donates half of 

the cost savings to the state. As a result, the greater the cost savings are the larger the donation 

to the state. 

A number of factors impact the cost of converting a rig into a reef, and subsequently, the cost 

savings associated with reefing. The size, location, water depth, method of removal, and 

proximity of the platform to the permitted reef site all affect the cost of the operation. 

 

7

 Because of the prohibition on using explosives in the water column, abrasive or mechanical cutters are used to cut 

the jacket at a safe navigational depth specified by the U.S. Coast Guard (typically 85 ft). 
12

Environmental, engineering, and market conditions introduce additional uncertainty and can also 

have a significant impact on the operation. It is difficult to enumerate and measure all the 

characteristics that might be important, but in practice, it is only necessary to consider a set of 

factors that describe the essential elements of the process. 

1.7.1. Complexity 

The size and weight of a structure are important parameters since they determine the size and 

type of construction equipment required in the operation. The derrick barge (DB) required is 

determined by the water depth in which the DB can operate and the lift capacity of the cranes. 

The minimum DB required to remove a structure is determined by the maximum load weights 

expected during the operation, which in turn, is determined by the weight of the deck and jacket 

and the cutting methods employed. In shallow waters, the deck is normally the heaviest lift, 

while in deepwater, the jacket weight normally exceeds the deck weight. Decommissioning cost 

generally increase with the complexity of the structure and water depth at the site (Kaiser et al., 

2003), and so we would suspect that the average donation for 3- and 4-pile structures would be 

less than 8-pile structures, for all other things equal. 

1.7.2. Location 

The location of a structure is determined by its latitude and longitude coordinates. Location is an 

important factor since it determines the distance to the onshore support facility, water depth, and 

distance to the nearest reef site. Distance to shore is an important variable since as the distance 

increases so does the transportation and related service costs. Tow distance to the nearest reef 

site is an important variable, since as the tow distance increases, the cost savings associated with 

reefing would be expected to decline. In water depth less than 100 ft, it is almost always more 

cost effective to dispose of the structure onshore rather than to transport the structure to a distant 

reef site. For large platforms in deep water, partial removals and toppling-in-place options are 

more frequently applied. Structures towed to site are expected to contribute less than the topplein-place and partial removal option due primarily to the additional expense of towing. Structures 

towed to site are also expected to have a greater probability of cost overruns since the owner is 

usually more exposed to weather and other delays. 

1.7.3. Water Depth 

Water depth is an important characteristic in offshore operations since increasing water depth 

requires the size and weight of a structure to increase, increasing the cost of decommissioning 

and reducing operational flexibility. Diving operations become more expensive because of diver 

restrictions on the amount of time underwater, activities are more exposed to weather conditions, 

etc. The USCG maintains requirements on the minimum clearance between the top of a reefed 

structure and the water surface, and so the minimum water depth for structures converted to reefs 

generally range between 80-90 feet. 
13

1.7.4. Removal Method 

A structure donated as an artificial reef is either towed to site, toppled-in-place, or partially 

removed. The cost of a partial removal relative to the topple-in-place option depends upon sitespecific conditions. In a partial removal, the jacket is cut in the water column, while the piles are 

left in place. Cutting in the water column necessitates the use of mechanical and abrasive cutters 

and, frequently, the use of divers, which generally cost more and creates greater risk to human 

safety8 than explosive techniques. However, nonexplosive water column severance is generally 

more environmentally friendly than a below mudline explosive cut. The direction of cost 

savings and risk is determined by engineering considerations, the experience of the contractor, 

and the success of the operation. 

1.7.5. Exogenous Events 

Offshore operations are highly sensitive to the weather/ocean environment and can suffer 

economic losses because of adverse conditions. Wind, waves, current, and weather impact 

operations throughout the year, especially during the winter season, November 30 - March 1, 

when drilling, construction, and deconstruction activities are particularly at risk. Weather may 

delay the operation or require the crew to demobilize to shore. Technical complications and 

other conditions may also delay operations; e.g., the use of explosives requires the water column 

and general vicinity of the structure to be clear of mammals and sea turtles prior to detonation. 

Market conditions, and the demand for and supply of liftboats, DB spreads, cutting spreads, and 

diving support vessels influence not only the cost of the service but also the time when the 

operation commences. 

1.7.6. Tow Distance 

Tow distance to the nearest reef site is an important variable, since as the tow distance increases, 

the cost savings associated with reefing declines. Structures towed to site are expected to 

contribute less than the topple-in-place and partial removal option due primarily to the additional 

expense of towing. Structures towed to site are also operationally more risky since the owner is 

more exposed to weather delays and other delays. 

1.7.7. Scale Economics 

Operators attempt to reduce the cost of decommissioning through scale economies. By bundling 

structures in a group and servicing the group as a unit, scale economies can frequently be 

achieved. The cost to decommission a group of structures as a unit is typically less than for 

separate operations due to savings from mobilization, shared expenses, and operational 

efficiencies. 

 

8

 Worker exposure to low-level risks over long periods is generally tolerated in offshore construction activity, but 

significant efforts are taken to avoid high-level, short-term risks. 
15

2. LOUISIANA ARTIFICIAL REEF PROGRAM

The Louisiana Artificial Reef Program (LARP) is the largest rigs-to-reefs program in the world, 

and is unique in its almost exclusive use of oil and gas structures for reef construction. In 1986, 

Louisiana became the first state to create an artificial reef program under the guidance of 

National Fishing Enhancement Act and authorization of the Louisiana Fishing Enhancement Act. 

Between 1987 and 2003, 120 structures worth over $20 million were donated benefiting both the 

petroleum industry and the state. Although the proportion of rigs donated as artificial reefs is a 

small fraction of the total number of oil platforms decommissioned each year, these artificial 

reefs are important for fish reproduction and attraction. 

In this chapter we review the regulatory structure of LARP, discuss the nature of the cost savings 

associated with reef donation, and construct regression models that quantify the donation 

amount. 

2.1. Background 

2.1.1. Donation Requirements 

Operators that donate a platform as an artificial reef can often lower the cost of decommissioning 

below the cost to bring the platform to shore for disposal, but many factors are involved in 

determining the cost of decommissioning a rig or turning it into a reef, and subsequently, the cost 

savings associated with reefing. The usual practice is for the state and operator to obtain a thirdparty estimate of the cost for removal alternatives before decommissioning is performed, and 

from these estimates, the donation amount is negotiated with the cost savings split between the 

operator and state. Formally, if the expected cost to remove a structure to shore is denoted 

E[C(Shore)], and the expected cost of reefing is denoted as E[C(Reef)], then the expected cost 

savings are estimated as the difference E[∆]: 

E[Δ]= E[C(Shore)] – E[C(Reef)]. 

If the expected cost savings are large and positive, it is likely the structure will be reefed, with 

operators donating one-half of the expected savings into the Louisiana trust fund for 

administration and related activities. If the expected cost savings are small, or negative, it is 

unlikely the structure will be reefed. A risk premium is usually implicit in the decision, since the 

donation amount is determined prior to the operation, and there is no way for the operator to 

adjust the values if unforeseen circumstances9

 occur. 

2.1.2. Liability 

BOEMRE regulations provide that a platform operator may be released from removal obligations 

in the federal lease instrument if a state agency responsible for managing fisheries resources will 

accept liability. The Louisiana Fishing Enhancement Act of 1986 established the state of 

 

9

 Decommissioning operations are usually performed on a turnkey (lump sum) basis, but the contractor may be 

required to perform “extra work” not covered in the scope of work and not included in the base bid. The operator 

accepts the risk of cost overruns and does not share or pass through this expense. 
16

Louisiana as the permittee for artificial reefs developed under the program’s jurisdiction and 

appointed the Department of Wildlife and Fisheries as agent for the state. The state assumes 

ownership of the structure after being donated to the reef program and is responsible for the cost 

of buoy construction and replacement, operation, and liability in perpetuity. The donor and other 

participants constructing a reef under NFEA and Act 100 are absolved from liability provided the 

terms and conditions of the reef permits are met. 

2.1.3. Artificial Reef Planning Areas 

Louisiana has designated nine approved sites for the disposition of artificial reefs (Figure B.1, 

Table B.1). These areas were identified by various user groups and employed both exclusion 

and inclusion mapping techniques (Wilson and Van Sickle, 1987). First, areas inappropriate for 

reef development were identified. This process, known as “exclusion mapping,” eliminated 

areas due to navigation fairways, pipeline corridors, military zones, live bottom areas, bottom 

type and hydrological conditions, and commercial fishing usage. Geologic and man-made 

features such as faults, gas pockets and rents, sediments of low bearing capacity, irregular and 

steep seafloor topography, active and relict channels, scarps, salt diapers, natural reefs, pipelines, 

platforms, subsea production facilities, and unstable areas were identified and assessed from data 

collected through various geophysical survey features. When exclusion mapping was completed, 

a series of public hearings were held across south Louisiana to outline the plan and solicit public 

input where reefs should be located (Kasprzak, 1998). Inclusion mapping identified the use 

patterns of recreational fisherman, commercial fishermen, sport divers, menhaden and shrimp 

fisheries. As a result of the hearings and public input, nine planning areas were selected for 

artificial reef development. 

Louisiana has a deepwater planning area in waters greater than 400 ft. Under the current policy, 

BOEMRE does not allow reefing outside of planning areas and established Special Artificial 

Reef Sites (SARS). 

2.2. Descriptive Statistics 

2.2.1. Structure Donation 

The number of structures donated to LARP and donation amounts by year are shown in Table 

B.2. From 1987-2003, 117 structures were donated to LARP – 63 3- and 4-pile jackets, 54 8-pile 

jackets, one barge, one tug, and one deck. Ten of the 117 structures donated to the program were 

destroyed by hurricanes. As of May 2004, LARP’s trust fund has accrued $20.8 million (M) for 

the administration and related activities of the program. The number and amount of donations 

vary with time, and over the past decade, about eight structures have been donated per year at a 

total annual donation of $1.37 million, or $169,000 per structure, on average. 

2.2.2. Program Statistics 

In Table B.3, the average donation amount per structure and per pile is shown according to 

removal method and structure type. From 1987-2003, 80 structures were towed to location, 29 

were toppled-in-place, and 8 structures were partially removed. Partially removed and toppled-
17

in-place structures were aggregated in the category “not towed.” The average donation for a 

structure towed to site is $117,000 versus $233,000 for structures not towed,10 with $21,000 and 

$37,000 the average donation per pile, respectively. Structures towed to site are expected to 

contribute less than the topple-in-place and partial removal option due in part to the cost11 to tow 

the rig to location. For structures reefed in place, waivers for site clearance and verification may 

be granted further enhancing the cost savings of these operations. 

 

Decommissioning cost generally increases with the complexity of the structure and water depth 

at the site (Kaiser et al., 2003), and so we would suspect that for 3-pile and 4-pile structures the 

donation will be less than for 8-pile structures, and indeed, this is generally confirmed by the 

data. For structures towed to location, the average donation per structure increases from $47,000 

(3-pile) to $97,000 (4-pile) to $150,000 (8-pile). For structures toppled-in-place and partially 

removed, the trends are subverted, from $450,000 (3-pile) to $246,000 (4-pile) to $212,000 (8-

pile), probably due to the small sample size and more diverse nature of the removal methods. On 

a pile-normalized basis, economies of scale are evident across the 4-pile and 8-pile categories 

since the donation per pile decreases with the number of piles. 

2.2.3. Operator Involvement 

ChevronTexaco owns the most infrastructure in the GOM, and so it is not surprising that they 

have also donated the most platforms to LARP. Six operators – KerrMcGee, CNG, ExxonMobil, 

Apache, Forest Oil, and Hunt – have each donated six or more structures (Table B.4). 

ChevronTexaco and Forest Oil have contributed more than one-third of the total program 

donations. Thirty-seven operators in total have participated in the program, with 15 operators 

contributing over 75 percent of the total donation. 

 

2.2.4. Capture Probability and Removal Method 

The percentage of structures reefed as a function of water depth is computed as the ratio of the 

total number of structures reefed divided by the number of well protectors (WP) and fixed 

platforms (FP) removed over the time horizon 1987-2002: 

P(Reef) = Number removed structures

Number reefed structures . 

Caissons are generally not considered candidates for reef material, and so only well protectors 

and fixed platforms are counted. The time horizon for enumeration begins from the inception of 

LARP and the CGOM planning area is used as a geographic proxy of the pool of candidate 

structures (Table B.5). Structures in 100 ft water depth or less are almost always brought to 

shore for recycling, while above 100 ft, the frequency of donations increases rapidly. Thirteen 

 

10 If one “outlier” point is removed from the set (a $2.5 million donation), then the average structure donation and 

donation per pile are $170,000 and $26,000, respectively. 

11 The average donation per towed structure is roughly $53,000 less than the average donation for structures not 

towed, and since the average tow distance was 20 miles, the inferred cost to transfer a platform to a reef site is 

estimated as (53,000)2/20 = $5,300/mile. 
18

percent of all “eligible” CGOM structures have been reefed since the creation of LARP, with 

more than half of the structures in water depth greater than 200 ft reefed during this time. 

The percentage of structures partially removed (PR) or toppled-in-place (TIP) as a function of 

water depth is computed similarly: 

P(TIP/PR) = Number removed structures

Number TIP/PR structures

. 

Platforms in deepwater are more likely to be reefed in place due to the higher operational costs 

and the additional savings that result from in-situ removals. This trend is expected to continue. 

 

2.3. Model Development 

2.3.1. Model Specification 

The program donation for structure s is modeled through a linear functional, 

DON(s) = αi + ∑α Xii , 

where the dependent variable is the donation, DON(s), reported in dollars, and the descriptor 

variables are described by X1 = WD = water depth (feet), X2 = DIST = distance to reef site 

(miles), X3 = NP= total number of piles, and X4 = TIP = topple-in-place or partial removal 

option. All the variables are numeric except the topple-in-place variable which is a binary 

indicator expressing if the structure was toppled-in-place or partially removed: TIP = 1, structure 

toppled-in-place or partially removed; TIP = 0, otherwise. Note that if DIST = 0, then TIP = 1, 

and if DIST > 0, then TIP = 0. 

The coefficients of the functional, αi, i = 0, 1, ..., 4, are estimated through least-square 

regression. The coefficient α0 represents a fixed term component, while αi, i = 1, ..., 4, are 

associated with the corresponding model variables. Decommissioning cost generally increases 

with water depth and structure complexity, and so the coefficients of the variables WD and NP 

(α1 and α3) are expected to be positive since the donation is expected to increase with these 

variables. As the distance towed to a reef site increases, one would suspect that potential savings 

resulting from rig donation would decrease, and we hypothesize that the coefficient of the DIST 

variable should be negative. Structures toppled-in-place or partially removed are expected to 

save more in decommissioning cost than a towed structure, and so the α4 coefficient should also 

be positive. 

 

2.3.2. Model Results 

The regression model results are depicted in Tables B.6-B.8. In Table B.6, reef donations are 

disaggregated according to removal method. In Table B.7, structure disposition is decomposed 

in terms of structure complexity, and in Table B.8, models that normalize donation by the 

number of piles per structure are constructed. 
19

In Table B.6, the regression model results provide a reasonably good indicator of the expected 

donation, especially for structures towed to location. Most of the model coefficients are 

statistically significant and of the proper sign. In Table B.7, reefed structures are disaggregated 

as a function of complexity. The range of the model fits are large but are considered reasonable 

for the factor set employed. In Table B.8, models that construct donation amount normalized by 

the number of piles are constructed. All the coefficients of the models are of the expected sign. 

 

All cost estimates describe the outcome of an engineering estimate performed prior to the 

operation, which may subsequently be modified through negotiation. Cost savings do not

represent the actual cost of the operation, and thus, are expected to exhibit weaker correlations 

with process descriptors than what otherwise would be expected. Water depth is the most 

significant variable across each of the models and donation is a negative function of tow 

distance, as expected. Additional variables might assist in deriving improved models, but the 

incremental improvement is likely to be marginal due to the nature of the processes involved and 

the limited ability of any factor set to capture the variability of the operation. 

2.3.3. Example 

Consider an 8-pile structure (NP = 8) located in 110 ft water depth (WD = 110) that is a 

candidate for reefing. The nearest reef planning area is located 15 miles away (TOW = 15). 

Predict the donation if the structure was reefed. 

From Table B.6, for a structure towed to location, 

sDON −= + − + = 580,69$)8(831,11)15(282)110(740238,102)( . 

 

From Table B.7, the model results yield, 

sDON = + − = 534,56$)15(323)110(222069,37)( , 

and from Table B.8 we obtain, 

)24(47)120(156485,10 =−+−=

)(

)(

sNP

sDON $5,970/pile, 

or since the structure is an 8-pile, 8($5,970) = $47,760. The difference in the donation estimates 

using the various models is due in part to the model uncertainty, the data employed to construct 

the models, and the preference of the user in model selection. It is difficult to know which of the 

three models is the “best” predictor of cost savings, and the user may apply the model with the 

optimum fit or choose another criteria to select a model. A range of values that bound the 

donation amount is probably the best approach to follow. 
21

3. TEXAS ARTIFICIAL REEF PROGRAM

The National Fishing Enhancement Act (NFEA) of 1984 was designed to promote and facilitate 

efforts to establish artificial reefs for the purpose of enhancing fishery resources and commercial 

and recreational opportunities. In 1991, the Texas Artificial Reef Program was established based 

on the guidelines of the NFEA. Currently, 35 permitted reef sites from over 70 decommissioned 

platforms have been created offshore Texas. 

The purpose of this chapter is to review the regulatory background and program statistics of the 

Texas Artificial Reef Program (TARP) and to construct quantitative models that describe the 

program donation. The history and organizational structure of TARP is first outlined. 

3.1. Background 

3.1.1. History 

Resource managers have been involved in artificial reef development offshore Texas for over 50 

years, and by 1984, over 2,000 de facto artificial reef areas had been created, including open 

water spoil disposal areas, piers and docks, jetties, liberty ships, and oil and gas well shell pads 

(Crowe and McEachron, 1986). Other than the liberty ships, however, most of these materials 

had little long-term success because they were easily broken up and moved by storms (Shively et 

al., 2003). Responding to the NFEA, in 1989 the Texas legislature directed the Texas Parks and 

Wildlife Department to develop the artificial reef potential offshore Texas, and in 1991, the 

Texas Artificial Reef Plan instituted the program (Stephan et al., 1996). 

3.1.2. Liability 

BOEMRE regulations release a platform operator from removal obligations in the federal lease 

instrument if a state agency responsible for managing fisheries resources accepts liability for the 

structure. The TARP established the state of Texas as the permittee for artificial reefs developed 

under the programs jurisdiction and appointed the Texas Parks and Wildlife Department as agent 

for the state. The state assumes ownership of the structure after being donated to the reef 

program and is responsible for the cost of buoy construction and replacement, operation, and 

liability in perpetuity. The donor and other participants constructing a reef under NFEA are 

absolved from liability provided the terms and conditions of the reef permits are met. 

3.1.3. Donation Requirements 

If the expected cost to remove a structure to shore exceeds the expected cost of reefing, then 

presumably reefing would be considered a viable alternative for the operator if the associated 

risks of the operations are comparable. Companies that donate structures to TARP are required 

to donate half of the expected cost savings from reefing into a trust fund to be used for research, 

administration, buoy maintenance, and other related activities. Third-party estimates of the cost 

for the removal alternatives are required before the operation is performed and from these 

estimated costs the donation amount is determined. Observe that since the estimated costs of the 

donation are determined prior to the actual operation, there is no way for the operator to adjust 
22

the values if unforeseen circumstances occur. Although decommissioning operations are usually 

performed on a turnkey (lump sum) basis, the contractor may be required to perform “extra 

work”12 not covered in the scope of work and not included in the base bid. 

3.1.4. Planning Areas 

Several permit options are available under TARP (Shively et al., 2003). The Galveston District 

COE developed a policy that allows 40-acre reef sites to be permitted as long as site location and 

material placement meet the guidelines of the plan. Each 40-acre permitted reef site 

encompasses 1/16 of a square mile (1,320 ft x 1,320 ft) and has enough space to cluster at least 

nine jacket structures. The initial donor at a permitted site is allowed to topple the structure in 

place if clearance restrictions can be met. Owners of nearby structures are encouraged to 

participate in the program by transporting their structures to the existing site to avoid additional 

permitting. Current BOEMRE policy only allows siting of new reef sites in the High Island 

General Permit Area. Existing sites are still open to accept reefs. 

Although many of Texas artificial reef sites are individually permitted, reefs created in the High 

Island leasing area are an exception (Figure C.1). Under the authority of a General Permit from 

the COE, artificial reefs created in the General Permit Area are constructed without the 

requirement of a 30-day public comment period. The permit requires the reef location to be at 

least 3 miles from another reef site, 2 nautical miles from any safety fairway and 1,000 ft from 

any active pipeline. In addition, the location must have at least 85 ft of water depth over the 

highest portion of the structure and must be at least one-half nautical mile away from any natural 

hard bottom communities (such as the Flower Garden National Marine Sanctuary East and West 

Banks). Reefs that do not meet these criteria require an individual permit from the COE issued 

after a 30-day public comment period. 

3.2. Descriptive Statistics 

3.2.1. Structure Donation 

The number of oil and gas structures donated to TARP and donation amounts by year are shown 

in Table C.1. From 1990-2003, 73 structures were donated to the program – 9 3-pile jackets, 39 

4-pile jackets, 25 8-pile jackets, one deck, and one caisson. A number of other objects have also 

been donated to TARP, including clay/shell culverts, tankers, fly ash blocks, concrete anchors, 

reef balls, quarry rocks, barges, buoys, net guard pieces, tugboats, and pipe structures (Shively et 

al., 2003), but such donations generally provide no “savings” to the owner or financial support to 

the program. As of May 2004, the Texas Artificial Reef Trust Fund has accrued approximately 

$9.6 million. 

 

 

12 If extra work is required that alters the critical path crane vessel time, the operator is charged at specified extra 

work rates. If extra work is required that does not alter the critical path crane vessel time, the operator is normally 

charged an hourly composite rate for all personnel and material required to correct the problem. 
23

3.2.2. Removal Methods 

From 1990-2003, 32 structures were towed (TOW) to a reef site, 16 were toppled-in-place (TIP) 

and 25 were partially removed (PR). In Table C.2, the average donation per structure (DON/NS), 

per donation (DON), and per pile (DON/NP) are shown according to removal method and 

structure type. The average donation varies with the structure type and removal method. For 4-

pile structures towed to site, the average donation is $17,382 per structure versus $143,107 for 

structures toppled-in-place and $174,178 for structures partially removed. On a per pile basis, 

the same general relations are maintained, with towed structures providing a donation of 

$4,346/pile, and topple-in-place and partial removal methods yielding $35,776/pile and 

$42,225/pile, respectively. However, fourteen of the 20 4-pile structures provided no donation, 

and thus, may not be “representative” cost saving for the category. As the number of piles 

increases, the donation per structure generally increases, while the donation per pile decreases. 

The donation per 8-pile structure ranges between $143,181 (TOW) and $244,875 (PR). 

3.2.3. Severance Method 

For structures towed to site or toppled-in-place, the conductors and piles need to be severed and 

removed from the seafloor. Explosives are the preferred means of severance and occur in 

roughly 80 percent of the operations; e.g., for 4-pile structures, 9-of-11 structures toppled-inplace and 16-of-20 towed structures, used explosives. Mechanical methods of severance were 

employed in all partial removals (Table C.2). 

3.2.4. Operator Involvement 

Cal Dive/Blue Dolphin Energy and El Paso have donated the most platforms to TARP, and in 

total, nearly 40 operators have made at least one donation to the program (Table C.3). El Paso 

and CNG have contributed over 25 percent of the total program donation, with 60 percent of the 

program donations contributed by 27 operators. 

3.2.5. Capture Probability Statistics 

The total number of structures removed in the WGOM from 1990-2002 is shown in Table C.4 

according to function type and water depth category. Removal statistics usually take a year or 

two after decommissioning is completed to be reported and included in the government database, 

and so the time frame of the analysis runs through the year 2002. Caissons are not considered 

appropriate reef material and are not included in the capture statistics. The probability a 

structure is reefed as a function of water depth is given by 

P(Reef) = Number removed structures

Number reefed structures . 

Structures in 100 ft water depth or less have about a 10 percent chance of being captured in the 

reef program, and in practice, structures in water depth less than 60 ft or so are almost always

returned to shore. Capture probability increases rapidly above 100 ft, with 65 percent of all 
24

removed structures in 101-200 ft, and 82 percent of all structures in 201-400 ft, reefed. In total, 

42 percent of all eligible WGOM structures have been reefed since TARP’s inception. 

3.3. Model Development 

3.3.1. Model Specification 

For structures donated to TARP, the donation amount is described through a linear model, 

sDON )( = α0 + ∑αi Xi, 

where the dependent variable is the donation reported in dollars, DON(s), and the descriptor 

variables are specified by X1 = WD = water depth (feet), X2 = DIST = distance to reef site 

(miles), X3 = NP= total number of piles (integer-valued), and X4 = NS = number of structures 

(integer-valued). Binary variables include structure type ST: ST = 0, 3-pile or 4-pile structures,

ST = 1, otherwise; topple-in-place removal TIP: TIP = 1, topple-in-place or partial removal, TIP

= 0, otherwise; and mechanical removal METH: METH = 1, mechanical cutting employed, 

METH = 0, otherwise. Note that if DIST = 0, then TIP= 1, and if DIST > 0, then TIP = 0. Since 

the TIP variable includes both topple-in-place and partial removal methods, TIP is not perfectly 

correlated13 with METH. 

 

3.3.2. Expected Signs 

Decommissioning cost generally increases with water depth and structure complexity, and so the 

coefficients of the model variables WD, NP, NS, and ST determined from regression are expected 

to be positive. As the tow distance increases, one would suspect that the potential savings 

resulting from rig donation would decrease, and thus we hypothesize that the coefficient of the 

DIST variable should be negative. Structures toppled-in-place or partially removed are expected 

to save more in decommissioning than a towed structure, and thus, provide a larger donation, and 

so the TIP coefficient is expected to be positive. Inclusion of the mechanical cutting variable

depends upon the decomposition strategy employed. 

 

3.3.3. Model Results 

The regression model results are depicted in Tables C.5-C.7. In Table C.5, reef donations are 

disaggregated according to removal method, and in Table C.6, models normalized by the total 

number of piles are constructed. In Table C.7, generalized models that incorporate all the 

descriptor variables are constructed. 

Water depth is the most significant variable in all the regression models, and although donation 

is a negative function of tow distance, the tow distance variable is generally not statistically 

significant. The number of piles is a significant descriptor and of the expected sign, but the 

 

13 If TIP was defined to only include the partial removal method, then TIP would be perfectly correlated with 

METH, since only mechanical methods or diver cuts are used in partial removals. 
25

coefficient of the number of structures is ambiguous. We would expect that the donation amount 

would increase with the number of structures donated, but scale economies may also occur 

which would dampen the effect. The donation per pile model is considered inferior to models 

where the number of piles is an explicit variable. 

All cost estimates describe the outcome of an engineering estimate performed prior to the 

operation. The actual costs of the operation do not effect the donation. Cost savings do not

represent the actual cost of the operation, and thus, are expected to exhibit weaker correlations 

with process descriptors than what otherwise would be expected in a traditional cost function. 

Water depth is the most significant variable across each of the models considered and donation is 

a negative function of tow distance, as expected. 

3.3.4. Example 

A typical application of the regression models is illustrated for a structure towed to location. 

Consider an 8-pile structure (NS = 1, NP = 8) located in 130 ft water depth (WD = 130) that 

needs to be towed 15 miles (TOW = 15) to the reef planning area. If the structure is reefed, the 

donation amount can be estimated as follows. 

 

From Table C.5, the donation function is written, 

sDON −= + 893543,156)( WD −193DIST + NP + 157,2852,14 NS , 

and after inserting the structure data, yields 

sDON +−= − + + = 765,59$)1(157,2)8(852,14)15(193)110(893543,156)( . 

From Table C.6 we obtain, 

+−= )1(275)15(83)130(218090,23 =+−

)(

)(

sNP

sDON $4,280/pile, 

or since the structure is an 8-pile, 8($4,280) = $34,240. From Table C.7, the generalized 

donation model yields sDON = .523,53$)(
27

4. IMPACT OF THE 2005 HURRICANE SEASON ON THE 

LOUISIANA ARTIFICIAL REEF PROGRAM 

There is extensive experience with decommissioning offshore structures and rigs-to-reef 

programs in the GOM, but significantly less experience for hurricane destroyed structures. The 

decision to repair, replace or abandon damaged and destroyed infrastructure, the manner in 

which decommissioning activities are performed, and the options available to operators are more 

complex and constrained compared to normal operations. The Louisiana Special Artificial Reef 

Site (SARS) program was created to accommodate structures destroyed in hurricanes and other 

exceptional circumstances to provide operators additional options for decommissioning. 

The purpose of this chapter is to review the status of the SARS program. We begin with a quick 

overview of the 2004-2005 hurricane season and review the risk associated with 

decommissioning hurricane destroyed infrastructure and the removal options available to 

operators. This is followed by a description of the criteria and procedures used to establish a 

SARS. The screening criteria employed in project evaluation and SARS approval concludes the 

chapter. 

4.1. 2005 Hurricane Season 

The 2005 hurricane season in the GOM was the most destructive and costliest natural disaster in 

the history of the United States, and was especially damaging to the offshore oil and gas 

industry. Five hurricanes passed through the GOM in 2005, but only Hurricane Katrina, a 

category 5 storm, and Hurricane Rita, a category 4 storm, caused damage (Figure D.1). 

Hurricane Katrina destroyed 44 platforms and severely damaged 20 others, while Hurricane Rita 

destroyed 69 platforms and damaged 32 others (Table D.1, Figure D.2). Eight drilling rigs were 

also destroyed and 19 rigs sustained significant damage. Katrina and Rita were responsible for a 

record $15 billion loss to the energy markets, two-thirds of which have been attributed to 

physical damage (Willis Energy Market Review, 2006). 

Offshore platforms are vulnerable to the extreme wind speed and wave height caused by 

hurricanes. Failure of primary structural components such as braces, jacket legs, deck legs, and 

piles often lead to listing or toppled units. Loadings caused by wave inundation of the deck are 

usually the primary cause of damage, since deck inundation increases the horizontal load and 

overturning moment, resulting in the failure of structural members and collapse (Figures D.3 and 

D.4). Bottom current loading or foundation failure may also lead to failure because of soil 

instability and mudslide conditions. Mooring on mobile offshore drilling units may fail, setting 

units adrift as they drag their anchors, before listing, capsizing, or grounding ashore. 

A structure destroyed by a hurricane requires a costly and time-consuming clean-up operation. 

There is extensive experience with decommissioning offshore structures in the GOM, but 

significantly less experience for structures destroyed by natural forces. Only a small fraction of 

the total number of removed structures, less than 3 percent or so, has been destroyed by extreme 

weather. Because hurricane events are random in nature, the geospatial distribution of destroyed 

structures is usually higher in high density regions, which are often distant to reef placement 

sites. 
28

The SARS category was created to accommodate reef materials that fall outside the planning 

areas of the LARP, but because of the manner in which the structures are laid down, special 

oversight is required to ensure that program criteria are met and that potential negative user 

impacts are minimized. Will the structure benefit recreational or commercial fishing, or fish 

habitat, at its current location, or should the structure be removed completely or transferred to 

another site? Will the site pose a threat to navigation or other users, or interfere with future oil 

and gas field development? Could the site serve as a biological field study or a location for 

future decommissioned structures? 

Regulators evaluate the technical and environmental aspects of each SARS project along with 

the trade-offs involved with establishing new reef sites outside the designated areas of the LARP. 

If the candidate structure satisfies criteria that enhances marine habitat, then it would be 

considered for possible inclusion as a SARS; otherwise, if it is determined that the structure does 

not benefit the marine habitat or poses a significant risk to other user groups, then it would be 

rejected as a SARS candidate and be removed in accord with federal requirements. 

4.2. Decommissioning Hurricane-Destroyed Infrastructure 

Under normal conditions, decommissioning operations are considered a safe and 

environmentally benign activity. Well-defined prescriptive regulatory policies safeguard human 

health and the environment, and because contractors have extensive experience in 

decommissioning, operational risk are well known and manageable (Schroeder and Love, 2004). 

From an international perspective, many of the issues that arise in the GOM take on specific 

regional characteristics; e.g., (Osmundsen and Tveteras, 2003; Hamzah, 2003; Parente et al., 

2006). In the GOM, the nature of the operation and short duration of the activity means that 

personnel are generally exposed to minimal safety risks. 

 

A structure damaged or destroyed in a hurricane complicates the decision-making process; it 

affects the decision14 to repair, replace or abandon the structure; the manner in which 

decommissioning activities are performed; and the options available to operators. Since 

hurricane destroyed structures are frequently toppled in place in neither a planned nor controlled 

manner, complications often arise in topsides removal and the wellbore plug and abandonment 

process. Removal options for destroyed structures are similar to normal decommissioning 

activity but are constrained by safety considerations, technology, available equipment, and cost. 

 

The risks involved in decommissioning hurricane-destroyed infrastructure are significantly 

higher than under normal conditions. A platform destroyed in a hurricane lies horizontally on the 

seafloor, often in a tangled web of steel (Figures D.5 and D.6), and in some cases, a significant 

portion of the structure may be submerged under mud. Preparation and inspection activities 

associated with normal decommissioning are forgone, and since the structure lies on the seafloor, 

well access is significantly more difficult and often requires the development of special 

equipment and tools to perform plugging operations. 

 

14 Several factors impact the decision to repair, replace, or abandon damaged and destroyed infrastructure. The 

return on investment from fabricating/installing a new platform, subsea assembly or pipeline interconnection 

depends upon the cost of removing/repairing the destroyed/damaged structure, the cost to re-enter/redrill wells, 

expected remaining reserves, current and expected future prices, operating cost and strategic considerations. 
29

Debris will need to be cut and moved by diving personnel or remotely operated vehicles to 

establish access to wells, and diver exposure time will greatly exceed the time normally required 

in operations, impacting the risk of the activity and significantly increasing cost. To remove 

topsides equipment, deck, and substructure may also require the development of special service 

vessels.15 Complete removal may not be technically feasible or may pose risks to diver 

personnel that exceed those of acceptable conditions. The cost to decommission a destroyed 

structure may range anywhere from 5-25 times the cost of a normal operation. 

4.2.1. Well Plugging and Abandonment 

The purpose of well plugging and abandonment (P&A) is to provide downhole isolation of 

hydrocarbon zones, protect freshwater aquifers, and prevent migration of formation fluids within 

the wellbore or the seafloor. Wells are shut-in prior to the arrival of extreme weather, and 

depending on the extent of damage, will either be temporarily or permanently abandoned. All 

wells on a lease must be permanently abandoned within 1 year after the lease terminates or if the 

BOEMRE determines that the well poses a hazard to safety or the environment or is not useful 

for lease operations and not capable of profitable oil or gas production. Economic and strategic 

considerations determine if the wells of a destroyed structure should be temporarily or 

permanently plugged. 

Shut-In Status 

A shut-in well is a flowing well that has its Christmas tree, master valves, wing valves, and 

subsea safety valve closed. Subsea safety valves serve to protect the environment from leakage 

should the topsides equipment be damaged or destroyed, and in the event that a structure is 

toppled, the subsea safety valve is the last line of defense preventing an oil/gas blowout. A well 

can be maintained in a shut-in state for any length of time as long as periodic maintenance 

procedures are followed. 

Temporary Abandonment Status 

In a temporary abandonment, the wellhead is removed, the producing formation is isolated with 

plugs, and casing is plugged below the mudline and a corrosion cap is inserted above the 

mudline (Kaiser and Dodson, 2007). A temporary abandonment is more secure than a shut-in 

well but is also more expensive to perform. Shut-in and temporarily abandoned wells are 

considered a temporary, or transitory, state in the life cycle of a well. 

Permanent Abandonment Status 

A permanent abandonment is the terminal state of a wellbore. In a permanent abandonment, 

former producing horizons are plugged and casing is cut off below the mudline according to 

 

15 A $30 million derrick barge called “The Bottom Feeder” was specially designed for hurricane clean-up operations 

and deployed out of Corpus Christi, Texas, on June 12, 2007 (Bahr, 2007). The Bottom Feeder consists of twin 

barges connected by steel truss frames that act as stabilizers as a targeted object is reeled up from the ocean floor. 

Four 200-ton winches attached to the trusses deploy hooks to retrieve sunken topsides and jacket components. The 

market dayrate for vessel utilization was $150,000 in September 2007. 
30

regulatory guidelines. Prior to operations, debris will need to be cleared around the site to 

establish access to the wellheads, and because of the loss of the structure, well access will be 

more complicated and expensive. P&A operations on destroyed structures take on many of the 

characteristics and cost of plugging a wet (subsea) well. 

4.2.2. Structure Removal 

Infrastructure destroyed by accident, terrorism, or natural catastrophe are decommissioned 

according to the same federal regulations that guide normal decommissioning operations, but 

depending upon the nature of the destruction and the market conditions in the months following 

the event, special conditions and delays may occur. Under normal conditions, the operator has 

three options for structure removal: complete removal, partial removal and toppling-in-place. 

These removal options for destroyed structures are similar to normal operations but are 

constrained by safety considerations, technology, available equipment, and cost. 

4.2.3. Site Clearance and Verification 

Site clearance and verification is the last task to occur in decommissioning. Under normal 

conditions, the operator has 60 days from the time the structure has been removed to clear the 

site and verify clearance. Clearance deals with the removal of oil and gas related debris that has 

accumulated on the seafloor at the production site, while verification ensures that the site is clear. 

Site clearance and verification requirements for reefed structures are frequently waived; for 

structures destroyed in a hurricane, steel and other material debris may remain on the seabed, in 

and around the site, if approved by the regulatory agency. 

4.3. LARP Statistics 

The number of structures donated to LARP, donation amounts, and average annual donation per 

structure are shown in Table D.2. Eight of the 147 platforms donated to LARP through 2006 

were destroyed by hurricanes, and 29 of the 147 structures exist as SARS. 

4.4. SARS Program 

4.4.1. Definition 

It was clear from the inception of the Louisiana Artificial Reef program that special 

accommodations would be required to capture “materials of opportunity” that arise from unusual 

and unforeseen circumstances. The Special Artificial Reef Site (SARS) program was created in 

1991 when a drilling rig collapsed in South Timbalier 86 during Hurricane Juan. A SARS is an 

artificial reef site created and maintained by the Louisiana Department of Wildlife and Fisheries 

to take advantage of materials of opportunity located outside designated planning areas. A site, 

and materials contained at the site, qualify as a SARS when one or more of the following criteria 

are met: (1) There is a historical or biological significance associated with the site, such as a 

successful fishing spot frequented by fishermen and/or divers; (2) The site is part of a 

cooperative effort between the LARP and other state, federal or private groups; (3) The site 

contains shipwrecks or other derelicts which cannot be practicably removed or relocated; or (4) 
31

The site forms an integral part of experimental or demonstration projects undertaken by the 

LARP. 

4.4.2. Selection Criteria 

Several criteria must be satisfied to be considered as a potential SARS location (Amendment II 

to LARP, 2003): (1) The site must provide benefit to recreational and/or commercial fishing, or 

fish habitat; (2) Removal of existing material from the site would have a negative impact on fish 

populations; (3) Designation as SARS would not pose a threat to navigation; (4) The area does 

not occupy currently trawlable bottom; (5) Inclusion of the SARS would have an overall positive 

impact on user groups; and (6) Except for possible trace amounts, the structure should be free 

and clear of any hydrocarbons or other hazardous materials. 

 

4.4.3. Procedures 

Procedures to review, and approve or reject, SARS applications were adopted in 1991 and 

revised and modified in 2003 (Amendment II to LARP, 2003). The program framework is 

meant to be transparent and provide equal non-discriminatory review to all applicants, as 

discussed in (Kaiser and Kasprzak, 2007). Formally, 

 

1) The Louisiana Artificial Reef coordinators will draft a proposal to establish a 

SARS for submission to the Artificial Reef Council. The proposal shall 

include location, clearance, bottom profile, condition of structure and list of 

potential hazardous material, and justification that the criteria outlined above 

are met. 

2) Following acceptance of the proposal by the Louisiana Artificial Reef Council, 

the intent to create a SARS will be announced through a Louisiana Department 

of Wildlife and Fisheries News Release. 

3) Thirty days following news releases, if no major objections are received, the 

Louisiana Artificial Reef Coordinator will apply for the necessary permits. In 

the event objections are received, a public hearing will be held to provide 

further information before a final determination by the Council. 

4) If appropriate, a Deed of Donation will be agreed upon by the donor and 

recipients of the reef material. 

5) The Secretary of the Department of Wildlife and Fisheries will sign all 

necessary permits and the Deed of Donation. 

4.5. SARS Program Statistics 

4.5.1. SARS Approvals 1991-2005 

Before the 2005 hurricane season, 29 structures destroyed in hurricanes, construction accidents, 

biological studies, and deepwater reef criteria were approved as SARS locations. These 

structures included two drilling barges and one drilling rig (Table D.3). Most SARS blocks have 

the capacity to accommodate between 7-10 platforms as shown in the development of SARS 

blocks WD-134, MP-243, and EI-313. At SARS blocks EI-273, EI-309, EI-322, EI-324, EI-384, 
32

SP-89, and VE-395, only one or two structures are currently contained per site, but the locations 

are likely to attract additional structures as future decommissioning activity occurs in the region. 

4.5.2. Post-Katrina SARS Approvals 

Following Hurricanes Katrina and Rita, the LARP Advisory Council held meetings to review the 

scope of the offshore damage and to discuss the expected impact on the program. Projects were 

screened with a Reef Priority Index (RPI) to prioritize projects received for consideration, and 

then evaluated on a case-by-case basis, taking into account factors such as the habitat value of 

the project, fishing reports available at the site, ability of the site to serve as the location for 

additional structures, distance to nearby planning areas and other SARS sites, clearance, relief, 

pipeline issues, and proximity to mud slide prone regions. The Advisory Council made 

recommendations to approve, to approve with modification, to discuss for future planning 

purposes, and to reject. Rejected projects cannot be resubmitted for future evaluation. 

Locations with no active pipelines transversing the lease were preferred SARS candidates, and 

active pipelines within or bordering a lease were reviewed when the distance was less than 1,000 

feet. Mud slide prone areas are generally not appropriate for reef sites, since platforms may 

move, break, and/or become submerged over time, and submerged/buried platforms provide little 

or no habitat value. Project modifications typically require platform additions or removals at a 

proposed site, and discussion for planning purposes is normally centered around the suitability of 

the site for future additions. 

 

In June 2006, 25 projects representing 39 destroyed platforms were submitted for SARS 

consideration. In total, 7 projects representing 21 platforms were approved (Table D.4, Figure 

D.7). 

 

In November 2006, 13 projects representing 25 platforms and 3 Mobile Offshore Drilling Units 

(MODUs) were reviewed for SARS consideration, including new and previously 

reviewed/reconfigured projects. Three projects representing 14 platforms were approved (Table 

D.4 and Figure D.7). None of the MODU projects were recommended for approval. The level of 

project submissions are believed to have peaked, and it is anticipated that SARS submissions 

from the 2005 hurricane season will clear by the end of 2007. 

At the end of 2006, 10 projects representing 35 platforms have been approved as new SARS 

locations, effectively doubling the number of SARS locations within LARP. The Council has 

stated its desire to accommodate structures that provide suitable habitat value while minimizing 

the total number of sites. This has generally required operators to group/bundle multiple 

destroyed platforms at one site to gain Council approval. For each SARS that is added to LARP, 

it is required that an equivalent area be removed from one of the nine designated areas, but 

because the number and size of SARS regions are so small relative to the total LARP area, the 

impact on the physical makeup of LARP regions is minor. As SARS locations are added to 

LARP, the LARP begins to take the regulatory characteristics of the Texas Artificial Reef 

Program, where operators are provided more flexibility in permitting partial removals and 

toppling-in-place (Shively et al., 2003). 
33

4.5.3. RPI Screening Criteria 

The majority of the destroyed infrastructure from the 2005 hurricane season was located in the 

federal waters offshore Louisiana. State officials were inundated with requests from operators to 

establish individual SARS locations at a number of these sites. A RPI was created to screen 

projects and to identify the most worthy candidates. 

RPI is defined on a project basis as follows: 

RPI = HV(A+B+C), 

where the habitat value (HV) represents the number of platforms involved in the project, and A, 

B, and C are weight factors based on the distance of the project to the nearest reef site (REEF), 

distance to shore (SHORE), and clearance at the site (CLEAR). HV enters RPI multiplicatively, 

so there is a preference for two or more platforms to comprise a SARS. The value of the 

weighing factors are as follows: 

⎪

⎩

⎪

⎨

⎧

>

≤<

≤

=

,3 10

2,2 10

,1 2

REEF

REEF

REEF

A 

⎪

⎩

⎪

⎨

⎧

>

≤<

≤

=

,1 70

35,2 70

,3 35

SHORE

SHORE

SHORE

B 

⎪

⎩

⎪

⎨

⎧

>

≤<

≤<

=

,1 130

85,3 130

50,2 85

CLEAR

CLEAR

CLEAR

C . 

The distance to the nearest reef site (REEF) and shore (SHORE) is measured in miles; clearance 

(CLEAR) is measured from the top of the submerged structure to the water line in feet. 

The weight factors serve to distinguish traits important in project definition. As the distance to 

the nearest reef site increases, it is more likely that towing the structure to the site would not be 

economic. The value of A gives greater weight to projects that are farther away from a 

designated reef site. The value of B is related to the distance to shore. A site within 35 miles to 

shore is given priority since such a site would be the most likely to attract recreational fisherman, 

while as the shore distance exceeds 70 miles, the weight factor drops to unity. The amount of 

relief at a site is an important factor in habitat value. The best habitat conditions for reefs 

maintain the greatest amount of relief within the clearance requirements specified by the Coast 

Guard. The value of C reflects the preference for structures that have 85-130 feet clearance. 

The RPI values for approved SARS projects are shown in Table D.4 and average 26.2 per 

project. Average RPI values for the 27 rejected SARS projects was 6.5 per project. 

4.5.4. Notable Applications 

Three SARS projects are of particular interest. One of the first SARS approved was for the 

Typhoon tension leg platform, a deepwater floating structure in GC-237 which broke free of its 

tensioned legs and floated nearly 100 km from its original location before capsizing. In June 

2006, Typhoon was accepted as a SARS in the Eugene Island 270 area. 
34

An 8-pile platform owned by Taylor Energy and servicing 28 producing wells in MC-20 failed in 

a mud-slide region. The platform was pushed nearly 400 feet from its original location, and 

upon inspection, was found to be submerged nearly 75 percent below the mudline. The volume 

of mud that will have to be dredged to access/lift the structure has been estimated to be 

equivalent to the volume of the New Orleans Superdome, and the project is expected to cost at 

least $500 million (Taylor, 2007a; Taylor, 2007b). As of June 2009, well plugging work is still 

on-going. The BOEMRE has called the project the most extensive well abandonment challenge 

in the Gulf of Mexico and is expected to require the construction of a coefferdam to allow 

workers to access the structure. The Taylor platform was submitted to SARS but was not 

approved because of the lack of habitat value. Being largely submerged below the mudline, 

there is little hard surface which could become useable reef. 

 

BP proposed a reef site for an 8-pile platform destroyed at GI-40/48, less than 3 miles from the 

Louisiana Offshore Operating Port (LOOP) anchorage area. Clearance restrictions will require 

lighted buoys at the site, and because of the proximity to LOOP, no final decision has yet to be 

made. Evaluation and risk assessment studies are on-going. 

4.6. BOEMRE Policy on Toppled Facilities 

After the 2005 hurricane season and the unprecedented number of SARS applications BOEMRE 

received to reef toppled structures, BOEMRE enhanced its review criteria for approving rigs to 

reefs proposals. 

4.6.1. Engineering, Stability, and Environmental Reviewing Standards

The BOEMRE GOMR will review each decommissioning application proposing Rigs-to-Reef to 

ensure that problematic engineering and/or environmental uncertainties are eliminated and the 

BOEMRE Rigs-to-Reefs Policy does not give the impression of a disposal program. The 

following set of standards will apply: 

1) Reef material must be stable and not endanger nearby infrastructure and/or 

protected resources: 

• No debris piles, debris fields, or reef baskets will be allowed under 

OCSLA regulatory permitting; 

• Reef sites will not be permitted in areas of seafloor instability or known 

mudslide activity; 

• Reef material must be established in the most stable orientation in its final 

disposition; 

2) Reef sites must be free from all potentially hazardous/nonstructural material: 

• Standing Decks – all nonstructural components must be removed (i.e., 

equipment, vessels, piping/tubing, wiring, etc.) and a facility inspection 

must be conducted/documented by BOEMRE or a third-party prior to 

reefing; 

• Submerged Decks – all decks and their separated components/equipment 

must be removed; 
35

3) Reef sites must not hinder future OCSLA oil and gas, marine mineral, and/or 

renewable energy/alternative activity operations: 

• Future reef sites will not be allowed within 5 miles of established/pending 

reef locations to minimize the impact to future pipeline operations; 

• Future reef sites will be reviewed for impact to future resource extraction 

(e.g., oil, gas, sulphur, and sand resources); 

4) Reef sites must not lead to avoidable space-use conflicts with other users of the 

GOM OCS: 

• Some proposals may require public review/commenting periods under 

NEPA (primarily a concern for abandonment-in-place); and 

• Reef sites that fall within the administrative/Coastal Zone Management 

Act boundary of another state could require coordination/consistency 

review by both applicable agencies. 

4.6.2. Reef-Approval Guidelines

Pending additional policy coordination between necessary State and Federal agencies and the 

opportunity for public participation, BOEMRE GOMR will only grant Rigs-to-Reef departures 

for platform-removal applications proposing the structure’s siting within any: 

1) New reef sites within the existing Texas General Reef Permit Area, Louisiana 

Artificial Reef Planning Areas, or Mississippi Artificial Reef Development Zone 

4; 

2) Existing/established artificial reef sites (i.e., previously reviewed and approved by 

BOEMRE GOMR) both within and outside of the areas previously mentioned; 

and 

3) Platform-removal permit applications with Rigs-to-Reef proposals received prior 

to implementation will be exempt from the Reef-Approval Guidelines; however, 

they will be subject to the applicable Engineering, Stability, and Environmental 

Reviewing Standards noted above. 
37

5. ASSESSMENT OF PLATFORM-BASED MARICULTURE IN THE GULF OF 

MEXICO

In this chapter, we discuss the prospects of an offshore mariculture industry in the GOM, 

specifically focusing on the alternative use of oil and gas infrastructure in the mariculture 

industry. We first describe a potential platform based OOA project and discuss the costs and 

benefits of using platforms in offshore mariculture including the ecological costs and benefits. 

We then review the offshore mariculture industry in the U.S. and discuss failed platform based 

projects. Next, we discuss site selection for offshore platform based mariculture in the GOM and 

end with conclusions. 

5.1. Open Ocean Aquaculture 

There has been a great deal of recent interest in open ocean aquaculture (OOA), the expansion of 

marine aquaculture to offshore areas (Marra, 2005; Skladany et al., 2007). Many commercial 

capture-based fisheries have already been depleted and their continued use is neither ecologically 

nor economically sustainable (Myers and Worm, 2003). Additionally, the culture of marine 

organisms, especially shrimp and salmon, in coastal areas has significant environmental impacts. 

As a result, the idea of raising marine organisms in large offshore cages for human consumption 

has become an attractive alternative to predatory fisheries and coastal aquaculture. 

Eighty-one percent of the seafood consumed in the U.S. is imported (approximately 3 million 

tons worth 13.4 billion dollars; (Upton and Buck, 2008)). To reduce this trade deficit, the U.S. 

Department of Commerce plans to quintuple the production of farmed fish, crustaceans and 

mollusks from just under $1 billion to $5 billion by 2025 (Skladany et al., 2007). Most of this 

increased production will be from an increase in the number of high value species farmed and 

much of this will come from mariculture. 

One of the largest obstacles to OOA is the isolation from onshore supply bases (Bridger, 2004; 

Stickney, 2004). OOA will require large amounts of food and energy to power automated 

systems as well as relatively large number of personnel to achieve economies of scale. 

There are several methods for the logistics of offshore aquaculture (Table E.1). The first option 

is to base crews on land and to make daily trips to the site. This is likely to be the most cost 

effective method for near-shore sites, but is unlikely to be feasible for farther offshore locations 

(Ryan, 2004). Even for nearshore sites, some kind of remote feeding and monitoring equipment 

may be needed for operations without permanent offshore personnel. The second is to use some 

type of special-purpose vessel that would stay on-site for extended periods (Ryan, 2004). 

Bridger and Goudey (2004) envision a jack-up barge that would service a dozen individual 

cages. The third option is to use existing oil and gas platforms as a base of operations (Figure 

E.1). However, suitable sites near shore are limited due to user conflicts, ecological impacts and 

geography and it may become necessary for OOA operations to locate further from shore and 

thus adopt an alternative logistical strategy. 

This co-development of offshore energy and mariculture resources has been studied since the 

early 1990’s (Caswell, 1991; Reggio, 1987) and several technical reports and feasibility studies 
38

have been conducted to investigate this possibility (Waldemar Nelson International, 2001; 

Louisiana Department of Natural Resources, 2005). Generally, these reports have concluded 

with positive analyses of the feasibility and prospects for the use of offshore infrastructure in the 

mariculture industry; however, there is yet to be a successful pairing of mariculture with the oil 

and gas infrastructure of the GOM, despite the fact that offshore aquaculture has developed 

elsewhere. 

 

5.2. Regulatory Authority 

The activity of platform-based mariculture in the Gulf of Mexico falls under the authority of the 

National Oceanic and Atmospheric Administration (NOAA). Under NOAA, the Gulf of 

Mexico Fishery Management Council developed the Aquaculture Fishery Management Plan 

(FMP) to establish a regionally-based regulatory framework for managing the development of an 

environmentally sound and economically sustainable offshore aquaculture industry in federal 

waters of the Gulf of Mexico. 

The primary environmental protections proposed in the FMP would: 

• Limit the species that may be cultured to Gulf Council-managed species 

(except shrimp and corals) that are native to the Gulf of Mexico. 

• Prohibit the culture of non-native, genetically modified, and transgenic 

species; prohibit aquaculture operations from being sited in habitat areas of 

particular concern, marine reserves, marine protected areas, Special 

Management Zones, and permitted artificial reef areas identified as such 

through Gulf Council FMPs and implementing regulations, as well as coral 

reef areas. 

• Create a restricted access zone for each permitted facility. 

• Cap the total amount of fish that could be cultured annually, as well as the 

relative contribution of each individual operation to the annual cap. 

• Establish a broodstock of organisms from the Gulf of Mexico to use in 

aquaculture facilities. 

• Establish numerous recordkeeping, reporting and operational requirements 

designed to minimize or mitigate potential environmental impacts. 

Other Federal agencies have regulatory authority for offshore aquaculture in the Gulf of Mexico 

as well. The Bureau of Ocean Energy Management, Regulation and Enforcement has regulatory 

authority over the right-of-use and easement of oil and gas platforms for aquaculture activities. 

The U.S. Army Corps of Engineers has regulatory authority over siting aquaculture facilities and 

the Environmental Protection Agency has regulatory authority with regards to water quality 

issues. NOAA has the regulatory authority to address marine resource conservation issues, 

which includes offshore aquaculture activities. 

 

5.3. Platform Systems 

There are a wide variety of methods for conducting marine aquaculture and a variety of potential 

aquaculture-related uses for oil and gas platforms. We focus on one potential use, the culture of 

finfish to maturity in large cages, serviced by an offshore platform. The system consists of a 
39

large fixed platform that is used as housing for staff, storage for feed and equipment, electricity 

generation and possible physical support for cages and a nearby shorebase which may also serve 

as a hatchery and nursery. Part of the platform might also be used as a nursery to allow fish to 

grow from their shipping weight to their stocking weight. 

We imagine that there will be several cages around a single platform. The cages will most likely 

be submersible (Figure E.2) as this generally allows for stronger cages able to withstand the open 

ocean, but they could also be of a net pen design (Figure E.2). 

Platforms could be acquired in one of several ways. A mariculture operator could purchase a 

platform from an oil and gas operator, a mariculture and oil company could co-use a facility 

simultaneously, or a mariculture company could rent the facility from an operator after its 

economically useful life has expired. Due to the potential for conflicts between the interests of 

the oil and mariculture operators, the simultaneous use of oil facilities seems the least likely.

5.4. Costs and Benefits of Using Offshore Oil and Gas Platforms 

Open ocean aquaculture does not require manned platforms in order to function. There are 

several locations around the world in which offshore operations function without platforms 

(Ryan, 2004). However, most of the existing offshore mariculture operations might be 

considered exposed rather than truly offshore (Bridger, 2004). There are a number of advantages 

that a truly offshore aquaculture system may accrue through the use of a platform. 

5.4.1. Advantages to Mariculturists 

Open ocean aquaculture is likely to require economies of scale in order to be economically 

viable. A large farm will require several full time staff, an electrical power supply for automated 

equipment and large amounts of food. By using a platform, supply boats could resupply the 

platform once a week or less rather than every day as in unmanned farms (Jin, 2008). This 

would save significant amounts of money and would ensure that brief weather events would not 

disrupt operations. There has been no study of the tradeoff between the capital and 

transportation costs associated with using platforms. However, Jin (Jin, 2008) did find that 

reducing the number of trips to a site by increasing vessel payload (as would occur through the 

use of a platform) increased the present value of a hypothetical operation approximately 2 to 5 

times depending on the distance from shore. 

 

Platforms would also allow for 24 hour on-site security and monitoring. These farms would be 

located miles from shore and may be subject to vandalism by opponents of the industry, theft or 

predator attacks. Even if remote monitoring systems are used, response times for shore-based 

personnel would likely be too long to serve as an effective deterrent. 

Depending on the cage configuration a platform might also serve as an anchor for nearby cages. 

It is not clear if all offshore oil and gas platforms could serve as appropriate anchors (Bridger 

and Goudey, 2004) but doing so might keep cages from drifting away during storms. However, 

anchoring cages to platforms could create strong lateral forces acting on the platforms during 

storms and could increase the risk of platform toppling. 
40

The GOM has a well developed service vessel industry with several ports distributed across the 

Gulf coast including Venice LA, Fourchon LA, Intracoastal City LA, Cameron LA, Sabine TX, 

and Galveston TX. This ensures that regardless of the location of the platform, there will be 

shore-based infrastructure nearby. 

5.4.2. Advantages to Oil and Gas Operators 

Advantages might also accrue to oil and gas operators. Companies must remove all structures 

from a lease within one year after production ends on a lease. Oil and gas operators could 

benefit by delaying the decommissioning of platforms due to the time value of money (assuming 

that decommissioning costs scale with inflation and that firms have investment options that 

exceed the rate of inflation; decommissioning costs may increase faster than inflation or slower 

than inflation due to technological learning). 

Oil and gas operators could also benefit by either charging fees for the use of their platforms or 

through the sale of platforms and the avoidance of decommissioning costs. It may be more 

advantageous and likely for operators to sell platforms then to rent them as this would decrease 

(but not eliminate) their liability exposure. Rents would have to be quite high in order to 

compensate for the increased liability (Fernandez, 2005). 

5.4.3. Disadvantages to Mariculturists 

A mariculture operator would have to acquire a surety bond that covered the cost of 

decommissioning the platform. Sureties are generally very conservative, and it would be likely 

that they would require a mariculture operation to collateralize the bond, requiring additional 

capital. The costs for a surety bond would range from 2 to 5 percent of the decommissioning 

costs per year to 100 percent collateralized bond in which the operator would have to provide the 

surety with the full value of the bond. 

It is also important to note that in the oil and gas industry, platforms are not generally 

decommissioned one by one, but instead an operator may decommissions all of the platforms in 

an area simultaneously, saving money through scale. This would not be an option for open 

ocean aquaculture. However, it might allow mariculturists an opportunity to use platforms that 

were past their economically useful life but not yet ready for decommissioning. 

The high capital costs associated with the purchase of oil and gas facilities could also be a 

disadvantage to using oil and gas facilities in offshore aquaculture. All open ocean aquaculture 

systems will require significant capital for cages, boats, onshore infrastructure and permitting 

expenses. The addition of the platform could add $1 million or more in capital costs. Studies 

have shown that open ocean mariculture projects are barely economically feasible without the 

additional expenses of platforms (Lisac and Muir, 2000; Kam et al., 2003; Posadas and Bridger, 

2003; Ryan, 2004; Jin, 2008; Kirkley, 2008). It is not clear if the added capital expense would 

be worth decreased operating expenses associated with decreased fuel usage. 
41

5.4.4. Disadvantages to Oil and Gas Operators 

One of the most important problems for operators interested in pursuing the sale of platforms to 

third parties is liability (Dougall, 1994). The liability to decommission a platform may be a 

larger cost than the platform itself. Decommissioning costs vary with the size and water depth of 

a platform, but for a 4-piled structure in shallow water (0 to 60 m) costs average $1.5 to 2.5 

million (Kaiser and Pulsipher, 2008). However, the liability, both for the mariculture operator 

and the original owner can be far greater. If a hurricane damages or destroys the structure, the 

costs of removal can increase dramatically.

The U.S. regulations stipulate that an offshore oil and gas operator can never be free of their 

obligations to decommission a site. Even if they pass ownership on to a mariculture operation, if 

that mariculture operator goes bankrupt and the funds are not available to decommission the site, 

the original operator would be liable. This is a significant disincentive for the original owner to 

sell or lease the site to an aquaculture operation. 

Supplemental bonds are required in the GOM for leases that do not meet a minimum financial 

threshold. For mariculture operations, it is conceivable that the Federal Government will require 

financial assurance to ensure that structure removal and site clearance operations will be 

performed in the event the operator goes bankrupt. For oil and gas structures that are 

transformed into a mariculture site, the supplemental bond will be similar to existing 

requirements as described in Kaiser and Pulsipher (2008) except that P&A requirements will 

likely have already been performed. 

5.4.5. Ecological Impacts 

The positive and negative ecological impacts of OOA have been discussed in a number of places 

(Riedel and Bridger, 2004; Goldburg and Naylor, 2005; Naylor and Burke, 2005). OOA is 

presumed to have fewer adverse ecological impacts than coastal aquaculture; however, there are 

many important negative ecological impacts including genetic pollution, nutrient discharge, the 

artificial selection and transmission of parasites, and a global decline of available fish protein. 

These ecological effects are applicable to all OOA projects. There are both additional positive 

and negative ecological impacts associated specifically with platform-based mariculture. 

By forestalling the removal of an offshore oil and gas platform, the habitat diversity associated 

with the platforms is maintained, leading to increased biodiversity. It has been estimated that 

10,000 to 30,000 fish live on each platform in the GOM (Stanley and Wilson, 2000) and the 

platforms in the GOM often provide the only locally available hard surfaces increasing local 

habitat diversity and biodiversity. Additionally, platform removal through explosives and site 

clearance through trawling can have localized impacts on nearby cetaceans and the benthic 

community, respectively; delaying platform removal will delay these impacts. 

However, it is also important to recognize that the use of oil and gas structures for mariculture 

could have significant impacts on the platform ecosystem. Platforms harbor diverse ecosystems 

and provide habitat for threatened and endangered species (Kolian and Sammarco, 2005). While 
42

the nutrient impacts of OOA are expected to be minimal compared to coastal aquaculture, they 

could still be locally important and could serve as a nutrient source for the associated platform. 

Adverse ecological impacts of drill cuttings from oil and gas platforms are well known (Grant 

and Briggs, 2002). Many platforms have large piles of cuttings lying beneath them; these 

cuttings can include mercury, a neurotoxin and carcinogen (Trefry et al., 2007). Additionally, 

large volumes of water are co-produced with oil and gas from offshore platforms. This produced 

water is separated from the oil and gas and either reinjected into a deep formation or discharged 

to the ocean (USDOI, MMS, 2006). Typically, produced water will contain hydrocarbons, 

corrosion inhibitors, biocides, demulsifiers, and radioactive materials. It is thought that produced 

water reaches non-toxic levels within 100 m of its release point due to dilution (USDOI, MMS, 

2006). However, finfish and shellfish species are known to have bioaccumulative characteristics 

(Shakhawat et al., 2006) and these molecules could bioaccumulate in fish causing adverse health 

effects in people consuming them (Lewis and Chancy, 2007). 

While devastating oil spills are rare in the GOM, BOEMRE predicts that over the five year 

period between 2007 and 2012, nine large oil spills (1,000 bbl or more), 50 small oil spills (50 to 

999 bbl) and 550 very small oil spills (under 50 bbl) will occur (USDOI, MMS, 2006). If any of 

these spills occurred near a mariculture project it could cause a catastrophic failure. 

A great deal of industrial activity occurs in the GOM on a daily basis. This industrial activity 

may, in some cases, cause noises that could stress fish. Sources of noises could come from 

nearby marine traffic, seismic exploration, explosive severance operations, drilling or 

construction, especially pile-driving. The effects of marine noise are not as well studied in fish 

as they have been in marine mammals, but studies have shown that the ears of pink snapper are 

badly damaged when exposed to nearby airguns with a maximum sound pressure of 203 dB at 1 

m (McCauley et al., 2003). Furthermore, when exposed to 30 minutes of ship sounds ranging 

from 128 to 162 dB three species of European freshwater fishes showed increased levels of the 

stress hormone cortisol. These results suggest that even non-lethal noises may have significant 

impacts on the operation of mariculture facilities in the GOM. 

The perceived as well as the real ecological impacts, both from the oil infrastructure on the fish 

and from the fish to the larger environment, are critically important for OOA. OOA is capital 

intensive and is most likely to succeed if the resulting fish can be marketed as healthy and 

environmentally responsible. Given that commercial and recreational fisheries exist in the most 

heavily industrialized sections of the GOM, it seems reasonable to assume that the ecological 

impacts of drilling on mariculture would be minimal or mitigable. Regardless of their actual 

environmental impacts, if oil and gas platforms are seen as dirty or polluted by the public, 

platform based OOA will have difficulty. 

5.5. Open Ocean Mariculture Projects 

There are several OOA projects in operation around the world (Skladany et al., 2007). The vast 

majority of these projects are not associated with platforms. A comprehensive review of these 

projects can be found in Skladany et al., (Skladany et al., 2007) or Halwert et al. (Halwart et al., 

2007). Four offshore projects are located in the U.S. including two farms in Hawaii (Hukilau 
43

Foods and Kona Blue Water Farms), one in Puerto Rico (Snapperfarm) and one in New 

Hampshire (University of New Hampshire Atlantic Marine Aquaculture Center). None of these 

use platforms as offshore bases. 

Snapperfarm began operating in 2002. They originally planned to raise cobia and red snapper, 

but after initial problems with red snapper they began stocking only cobia. Snapperfarm 

operates in collaboration with the University of Miami which provides fingerlings for the 

operation. They currently operate three, 3,000 m3 submerged cages and have successfully 

harvested several crops at a rate of a few tons per week. The depth at the site is 25 to 30 m 

(Benetti et al., 2007; Benetti et al., 2008). 

Kona Blue Water Farms operates an integrated hatchery and offshore grow out system for 

Almaco jack (Seriola rivoliana). They are the only commercial operator with an integrated 

hatchery. They market their product as environmentally sustainable and healthy with low levels 

of mercury and their fish was recommended as a good alternative to other farmed yellowtail 

species by the Monterey Bay Aquarium. Their site is less than one km offshore but in water 60 

m deep. They currently produce approximately 12 tons of fish per week which is now sold in 

restaurants across the U.S. (Kona Blue, 2008). 

Hukilau Foods (formerly Cates International) developed from a research project conducted by 

the University of Hawaii. Hukilau produces about 900,000 pounds (about 400 metric tons) of 

moi per year (as of 2007). Their four 3,000 m2 cages are 3.2 km offshore in approximately 50 m 

of water. Hukilau intends to expand production to 1.5 million pounds per year (680 metric tons) 

and to develop an integrated fish hatchery capable of producing 10 million fingerlings annually 

(Hukilau Foods, 2007). 

The University of New Hampshire Open Ocean Aquaculture program raises Atlantic cod, 

halibut, haddock, and flounder as well as blue mussels in an area 10 km off the coast of New 

Hampshire. The depth in the area is 60 m. Although they do sell their products, they are a 

research institute and not a commercial facility. They currently use two, 3,000 m2

 cages but 

have also tested several other cage designs and they have developed a remote feeding buoys that 

can hold and distribute 20 tons of feed (Atlantic Marine Aquaculture Center, 2007). 

5.6. Platform-Based Mariculture Projects 

5.6.1. International Platform-Based Projects 

Spain has a well developed offshore and near shore mariculture industry which developed in part 

due to a lack of sheltered sites along the coast (Cardia and Lovatelli, 2007). Spain also has one 

of the few operational platform based offshore projects in operation. Marina System Iberica 

(MSI) built four floating platforms along the Mediterranean coast. These platforms are steel 

structures that are moored to the seabed. Nine cages are attached on each floating platform with a 

total volume capacity of 18,000 m3 allowing production of 450 tons of fish a year. The 

freeboard of the platform can be adjusted to adapt to different sea climates through the ballasting 

system of its vertical columns. Four small buildings are located over the platform to hold the 

power generator, biological laboratory, feeding warehouse and crew dormitory. While this 
44

design is revolutionary in that in allows crews to permanently man an offshore fish farm, the 

structure is not fixed to the seabed. 

Since 1998, there have been three platform-based mariculture operations in Northern Hokkaido, 

Kumamoto, and Ehime. The Northern Hokkaido platform controls five cages, each 6,000 cubic 

meters (20×20×15 m). The feeding and monitoring systems are controlled by a computer which 

allows the onshore base to operate the daily feeding work remotely. Electronic power required 

by the operation is delivered by transmission wire on the seabed. This operation produces 80 tons 

of salmon and 160 tons of trout yearly. The North Hokkaido platform experienced a magnitude-6 

earthquake and 3-meter waves after it was established, but no damage was incurred. 

5.6.2. Texas Sea Grant Project 

There have been several attempts at using oil and gas platforms for mariculture in the U.S. 

(Table E.2), but thus far, none have reached commercial status. In the early 1990’s, the Texas 

Sea Grant program started the first platform based mariculture operation in the Gulf of Mexico. 

Texas Sea Grant scientists used an Occidental Petroleum platform as an offshore operations base 

to grow redfish in a net-pen (Waldemar Nelson International, 2001). During its operation, storms 

damaged some of the cages and fish escaped. According to the Sea Grant reports, the fish cost 

$22 per pound to raise and had a market value of $3.50 per pound (Gulf of Mexico Fishery 

Management Council, 2007). The project was eventually abandoned. 

5.6.3. SeaFish Mariculture LLC 

In the late 1990’s, Seafish Mariculture LLC proposed to utilize gas platforms offshore Texas for 

an OOA operation. SeaFish Mariculture operated from 1997 to 1999. The first group of red 

drum fingerlings was stocked on November 30, 1997. The platform was staffed in rotation by 

two, 2-person teams who lived on the platform and were transported to and from the platform via 

helicopter. Shell continued to operate the platform over this period. 

SeaFish Mariculture successfully raised red drum from 3-inch hatchery-raised fingerlings to 

market-size fish in a growth cycle of less than 12 months. However, the project encountered a 

number of difficulties including losses due to storms and cage movements necessitated by the 

needs of the oil and gas operator. In July 1999, SeaFish Mariculture notified NOAA Fisheries 

Service that it planned to terminate the project due to the needs of the operator to increase gas 

production at the site (Gulf of Mexico Fishery Management Council, 2007). 

5.6.4. Gulf of Mexico Offshore Aquaculture Consortium 

In February 2000, the Gulf of Mexico Offshore Aquaculture Consortium (OAC) was formed to 

create a university-based interdisciplinary research program to study the social, environmental 

and technological issues that impede mariculture development in the Gulf of Mexico. The OAC 

planned to place a cage adjacent to an oil and gas platform but did not plan to connect its cage 

directly to the platform or even to utilize the platform directly. OAC explained that the site 

selection was determined to minimize the number of potential user conflicts while increasing the 

protection to the cage. 
45

In May 2000, a Sea Station cage manufactured by Ocean Spar Technologies was assembled on 

the coast of Mississippi. The cage was towed to its mooring position, near the Chevron 990 

platform, approximately 40 km south of Pascagoula, MS, in 25m of water. According to the 

research plan, the cage would remain empty during the first year so that engineering and 

environmental monitoring could be conducted. In October 2000, the research cage broke free of 

its mooring and was carried to the northern end of Chandelier Island 10 km away (OAC, 2002). 

In July 2002, OAC redeployed its cage and adopted an improved mooring system developed by 

researchers at the MIT Center for Fisheries Engineering Research. OAC planned to stock the 

cage with red drum fingerlings (OAC, 2002). After July 2002, OAC no longer released news 

about this project, and according to correspondence from OAC, the project did not work as well 

as expected and the cage has been removed from the water. 

5.6.5. Grace Platform Project 

In 2003, Hubbs-SeaWorld Research Institute proposed a fish hatcheries and marine stock 

program for the Grace Platform offshore California. The 3-year research program was designed 

to test the feasibility of using offshore platforms as operational bases for the sustainable 

development of mariculture. The project was supported by Chevron Environmental Management 

Corporation, which funded the institute’s start-up costs and offered $10 million to run the 

operation for three years. According to some reports, Chevron hoped to avoid the expense of 

removing the Grace Platform by sponsoring this mariculture project (James and Slaski, 2006). 

The Grace Mariculture Project planned to suspend four, 125,000 m3

 cages off the platform. They 

planned to raise white sea bass, striped bass, California halibut, California yellowtail, bluefin 

tuna, red abalone, and mussels. In 2006, the Grace Mariculture Project had to abandon operations 

because of the owner's plans to develop an LNG gasification facility at the site (Hubbs-SeaWorld 

Research Institute, 2009). 

5.6.6. GMIT Project 

Gulf Marine Institute of Technology (GMIT) is a nonprofit research institute that partnered with 

Biomarine Technologies and Biomarine Fuel. In September 1998, GMIT was granted approval 

from the Texas General Land Commissioner to use a multi-platform oil and gas complex along 

the coast between Freeport and Corpus Christi (Poruban, 2000). However, in October 1999 the 

Texas General Land Commissioner reversed course and ordered GMIT to remove the platforms 

(Poruban, 2000) resulting in lawsuits that were settled in GMIT’s favor in late 2005. The 

company has not yet placed fish in the water but is still planning to do so. 

According to GMIT, the operators have invested $6.2 million for the acquisition of marine 

vessels and the platform complex. The platform removal liability bond for this project is $2.6 

million (Poruban, 2000). GMIT and Biomarine hope to eventually install 76 cages and realize an 

annual net income of $52 million. The company has estimated the project would create 1,100 

jobs (GMIT, 2007) (Table E.3). 
46

5.7. Site Selection 

Site selection is among the most important factors that can influence the ecological impacts and 

profitability of an offshore mariculture operation. GIS based models for identifying areas that 

are most suitable for offshore mariculture operations have been developed (Longdill et al., 2008). 

Here we describe in a qualitative way the factors that influence site selection and their 

prevalence in the GOM. 

5.7.1. Topography 

Topography is a major influencing factor in determining the operational suitability of offshore 

sites. Deepwater (30 or more meters) allows for the use of submerged cages which decrease the 

impact of waves (Huang et al., 2008). Many of the currently operational offshore sites are in 

water 50 to 60 m deep (all except Snapperfarm which is in 25 to 30 m of water). The continental 

shelf of the GOM slopes gently from the shore to a depth of about 200 m, approximately 100 to 

200 km offshore. Most of the existing oil structures are in this region. However, there are large 

areas with offshore infrastructure in which water depths are less than 25 m (Figure E.3). As a 

result, mariculturists might have to go further offshore to find suitable infrastructure. Ideally, 

mariculturists would find sites that were both close to shore and in relatively deep water (over 30 

m). 

The significant wave height impacting an area is also important as it can lead to stress on cages 

and may be impacted by topographical features such as reefs, islands, or peninsulas. These 

features can extend the duration of favorable weather windows, allowing more time for on-site 

operations, decrease the severity of extreme weather events and could also be associated with 

lower significant wave heights (Turner, 2000). Examples of these areas in the offshore GOM 

might include artificial reefs and the western side of the mouth of the Mississippi. 

Obviously, platforms close to shore will be preferred over those further from shore. For nonplatform-based projects distance to shore and ports will be of paramount importance for 

logistical reasons; this requirement is not as important for platform-based projects since the 

platform will allow for less frequent supply trips from shore. However, the supply vessels used 

in the oil and gas industry travel slowly and use large amounts of fuel. A small supply vessel 

might travel at 10 knots and use 50 to 100 gallons of diesel per hour, therefore, fuel and crew 

costs can be significant. In a study of offshore cod aquaculture, Jin (Jin, 2008) found that 

moving a hypothetical operation from 5 to 10 miles offshore decreased the average present value 

in three scenarios by $1.77 million, and moving from 5 to 25 miles offshore decreased average 

present value by $5.76 million. 

5.7.2. Water Exchange 

Because mariculture operations depend on water currents to supply oxygen and to remove 

wastes, fish farmers should locate their cages or net-pens where there is pollution-free high tidal 

water flow. However, dangerously strong current may cause high stress to fish and hazards to 

mariculture facilities. Optimum average current speeds will vary depending on the species of fish 

being farmed, but generally lie within the range of 0.1 to 0.5 meters per second (Petrell and 
47

Jones, 2000; Reidy et al., 2000). Average speeds beyond this range may force fish to expend 

more energy swimming, thus reducing growth rates, and may also impact the structural integrity 

of the cage (Huang et al., 2008). Average speeds below 0.1 meters per second may not provide 

adequate water exchange. Thus, there is a tradeoff between growth rate and water circulation in 

site selection (James and Slaski, 2006). Current velocities at the surface along the TexasLouisiana shelf are generally 0.2 to 0.3 m/s, within the optimal range (Louisiana Department of 

Natural Resources, 2005; Johnson, 2008). The weakest currents in the area of oil and gas 

infrastructure occur off the Louisiana coast near the Texas boarder while the strongest occur just 

to the west of the mouth of the Mississippi (Johnson, 2008). Importantly, there are areas of 

appropriate currents just off the Texas coast from Matagorda Bay to Corpus Christi; this is the 

area in which Biomarine and GMIT are basing their operation. 

5.7.3. Temperature 

Optimal temperatures vary among species but significant temperature fluctuations will adversely 

impact mariculture operations. In general, offshore sites are known to experience more stable 

temperature regimes than those found inland, thus reducing the probability of extreme 

fluctuations. Additionally, the use of native, non-migratory species will help to ensure that a 

proposed site has species specific optimal temperatures. Cobia, perhaps the best candidate 

species for open ocean aquaculture in the GOM, is native to the Gulf. 

5.7.4. Salinity 

In coastal regions salinity can be significantly influenced by nearby freshwater discharges. 

However, salinities are relatively constant in offshore sites. Most sites in the GOM will probably 

have stable and appropriate salinities for most pelagic species. All of the federal offshore oil and 

gas platforms are in areas that are not significantly affected by freshwater inputs. 

5.7.5. Oxygen 

Adequate oxygen levels are critical for all fish species. Some offshore locations adjacent to 

zones of upwelling can routinely experience oxygen levels as low as 3 mg/L (Rabalais et al., 

2002). Furthermore, algal blooms can cause significant decreases in dissolved O2. For example, 

the annual algae bloom in the Gulf of Mexico reduces O2 concentrations to as low as 0.5 mg/L 

(Rabalais and Turner, 2006). Long-term advance monitoring must indicate a minimum of 90 

percent O2 saturation and/or O2 concentrations of 7 mg/L. 

5.7.6. Algae Blooms 

The experience of the European mariculture industry indicates that algae blooms and large 

jellyfish populations may have serious negative impacts on farmed fish. Both of these factors can 

negatively influence the survival and growth rates of fish. 

In general, algal blooms are caused by large nutrient inputs into aquatic ecosystems. These algal 

blooms can be harmful to mariculture in one of two ways. First, algae can release toxins, for 

example ciguatoxin, which can bioaccumulate and reach high levels in fish. If fish with high 
48

levels of toxins are consumed by humans they can cause severe illness. Gambierdiscus toxicus, 

the dinoflagellate that contains ciguatoxin, is generally absent from the GOM; however, oil 

structures have been shown to provide a hard substrate which harbors G. toxicus (Villareal et al., 

2007). Similarly, Karenia brevis, the dinoflagellate that causes neurotoxic shellfish poisoning 

and respiratory disease in humans is also known to occur in the GOM (Stumpf et al., 2003). 

Secondly, when algae die they sink to the ocean bottom and decompose. This decomposition 

uses oxygen, which depletes the concentration of oxygen in the water and can cause an anoxic 

zone. Each summer, a 20,000 km2 hypoxic zone develops in the GOM due to the nutrient input 

from the Mississippi river (Rabalais et al., 2002; Rabalais and Turner, 2006). Fish generally flee 

this zone; however, Pichavant et al. (2000) demonstrated experimentally that turbot exposed to 

hypoxia grew significantly slower than turbot exposed to normal oxygen conditions. Thus, fish 

enclosed in cages in this area would be unlikely to grow as well as fish elsewhere in the GOM. 

This zone overlaps with many of the fixed platforms in the GOM and would have to be 

considered before any maricultural activity commenced (Figure E.4). 

5.7.7. Jellyfish Blooms 

Jellyfish blooms can damage the gills of farmed fish leading to mortality and decreased growth 

rates for surviving fish. The causes of jellyfish blooms are currently under investigation, but one 

potential cause could be the warming of the oceans (Purcell et al., 2007). Ocean temperatures 

will continue to increase in the coming decades (IPCC, 2007), therefore, the potential for 

jellyfish blooms, and the possibility of excluding them from net-pens, should be considered. The 

number of jellyfish have increased in the Northern GOM since the 1990’s and they have become 

distributed further offshore (Graham, 2001). In the summer of 2000 an invasive species, 

Phyllorhiza punctata, was first cited in the Northern GOM (Graham et al., 2003). 

5.7.8. Hurricanes 

Open ocean mariculture in the GOM will be impacted by hurricanes. Figure E.5 shows the 

tracks of the category 3, 4, and 5 hurricanes that impacted the GOM between 1983 and 2004. 

Since OOA operations will require many years (at least decade) to earn back the initial capital 

investment, operators should plan on dealing with one major hurricane and several smaller 

hurricanes and tropical storms. These storms can damage cages and can topple piled structures. 

Damage to cages can be mitigated by submerging cages in deep water. Damage to piled 

structures usually occurs when waves reach the height of the deck. The requirements for 

minimum deck heights have become more stringent over time. This, along with the subsidence 

that has occurred along the continental shelf, results in older structures being at a greater risk for 

catastrophic failure than younger structures (Laurendine, 2007). Figure E.6 shows the 

distribution of existing fixed platforms by age. Most older platforms are nearshore while many 

of the newer platforms, especially those outside of otherwise unacceptable areas, are far offshore. 

5.7.9. User Conflicts 

One of the more difficult aspects of using platforms for mariculture will be to manage user 

conflicts in the GOM. The GOM has a great deal of ship traffic from both cargo ships and 
49

commercial fishermen. Ship traffic is most densely concentrated close to the several ports that 

are heavily used as bases for offshore service vessels (especially Fourchon) and near the mouth 

of the Mississippi. While platforms are not directly in ship lanes, they may be located nearby 

and noise from passing ships could impact fish growth (Figure E.7). 

5.7.10. Proximity to Markets 

The GOM does have some significant advantages over commercial OOA projects now in 

operation. The three commercial OOA operators are located in Puerto Rico and Hawaii, far from 

many of their consumers. OOA operators in the GOM would, conversely, have nearby markets 

in New Orleans, Houston, Atlanta, Dallas, San Antonio, Mobile, Pensacola, and Baton Rouge, 

reducing the transport costs and times for their products. 

5.7.11. Suitable Platforms 

Using the information discussed in sections 5.6.1. through 5.6.10. and the GIS maps in Figures 

E.3 through E.7, we apply exclusion techniques to select platforms that might be most suitable 

for OOA use. These, along with bathymetry contours, are shown in Figure E.8. We selected 

only platforms outside of hypoxia zones, in greater than 25 m of water, and outside of shipping 

lanes. Out of the 2,427 fixed platforms, only 191 may be appropriate for OOA use. 

5.8. Removal and Reuse of Platforms 

Given the constraints of site selection, liability and co-use with oil and gas operators, it may be 

more feasible for mariculturists to attempt to reuse decommissioned platforms. In the oil and gas 

industry it is not uncommon for platforms to be brought to shore to be refurbished and reused, 

saving on the costs of new fabrication (Kaiser and Pulsipher, 2007b). Re-use opportunities in oil 

and gas are often constrained due to the specific requirements needed for facilities (number of 

slots, deck weight, jacket height, number and capacity of cranes, crew accommodations). The 

mariculture industry is likely to be more flexible in its needs and more likely to reuse refurbished 

platforms. 

The reuse of refurbished platforms would remove liability concerns from oil and gas operators 

and might decrease liability for mariculturists. The reuse of refurbished oil and gas platforms 

would also expand potential areas for site selection, especially to the eastern GOM and the coast 

of south Texas, which has relatively few platforms. Using refurbished platforms would eliminate 

concerns, real or perceived, about the impacts of raising fish adjacent to oil and gas production 

and their resultant pollution. Finally, using refurbished platforms would maintain the total 

amount of hard substrate in the GOM. While the ecological community living on and around the 

platform would be destroyed during the process of removing and refurbishing the platform, the 

replacement of that platform elsewhere in the GOM would lead to the eventual recolonization of 

the structure. 
50

5.9. Conclusion 

Platform-based mariculture is an attractive idea for the GOM as it provides a potentially 

sustainable food source while also providing an outlet for no longer useable oil and gas 

platforms. However, there are a number of disadvantages and constraints on site selection, 

which make platform-based OOA relatively unattractive to both oil and gas operators and 

mariculturists at the present time. 

Of all of the hurdles to platform-based mariculture, liability may be the greatest. Removing a 

platform can be expensive under ideal conditions, and if the structure is toppled by a hurricane, it 

can be financially ruinous. If a hurricane destroyed a platform-based mariculture operation, it 

would not only bankrupt the mariculture operator, but after collecting the value of any assets and 

bonds from the mariculture company, the federal government would hold the original operator 

liable. This provides a disincentive to oil operators to sell structures to mariculturists. 

Much of the GOM is not well suited for the use of oil and gas infrastructure in mariculture 

operations. This is most notable along the shallow continental shelf offshore western Louisiana 

and eastern Texas from Timbalier Bay to Galveston. These areas are unlikely to be suitable for 

offshore aquaculuture due to their shallow water and susceptibility to low dissolved oxygen 

levels. However, there are more suitable areas to the south and west of the mouth of the 

Mississippi, and offshore Texas from Port O’Connor to Corpus Christi. Both of these areas have 

relatively strong currents, high minimum dissolved oxygen and deep water. There is also an area 

to the south and west of Mobile Bay that has relatively deep water and potentially acceptable 

dissolved oxygen levels, but has weaker currents than elsewhere in the Gulf. If OOA develops in 

the GOM it is most likely to occur in these areas. 

Platform use would be best suited to cases in which near shore sites are somehow constrained. 

For those interested in the development of an OOA industry in the U.S., it may be more prudent 

to select sites relatively close to shore which would not require platforms. Only when these sites 

are developed will OOA be likely to spread further offshore, potentially necessitating the use of 

platforms.
51

6. ECONOMIC FEASIBILITY ASSESSMENT FOR PLATFORM-BASED 

MARICULTURE IN THE GULF OF MEXICO 

In the Gulf of Mexico, there has been strong interest over the years to utilize the existing oil and 

gas infrastructure to facilitate mariculture operations. The economics of such plans, however, 

are usually highly uncertain and subject to a large degree of technical risk. The purpose of this 

chapter is to evaluate the economic feasibility of platform-based mariculture operations in the 

Gulf of Mexico. We first review the available literature on the costs of offshore aquaculture. A 

scenario-based economic model is then developed to explore the feasibility of platform-based 

cobia aquaculture. We end with remarks on the viability of an offshore aquaculture industry in 

the U.S. 

6.1. Prior Studies of Offshore Aquaculture Costs 

There have been surprisingly few studies of the economic costs of offshore mariculture and a 

limited amount of data collected and published. Data from previous cost studies is shown in 

Table F.1. Most of the studies cited derive from theoretical estimates. As a result, the estimates 

differ markedly depending on the assumptions used in developing the model and the species 

selected and the type of offshore support system. 

The accuracy of the models is dependent on their assumptions and, since there is little available 

empirical data to inform these assumptions, it is difficult to draw conclusions about their validity. 

The assumptions of the models vary widely (Table F.2). In some cases, like feed conversion rate 

(FCR), this could be due to the species modeled; however, we might expect other assumptions, 

such as the cage cost to be roughly similar among models. Instead, the cage costs vary from 27 

to 89 $/m3

. 

Posadas and Bridger (2003) follow Bridger and Goudey (Bridger and Goudey, 2004) and model 

a system that uses a purpose built aquaculture support vessel. They assumed a barge costs $1.5 

million. Likewise, Ryan (Ryan, 2004) assumed that operators would spend $900,000 on each of 

three feed barges which would each store 600 tons of food. These capital costs are roughly 

similar to the cost of an offshore platform.

6.2. Methodology 

We built two net present value (NPV) models of the costs of a hypothetical offshore cobia 

culture system. Cobia is a fast growing species that is currently being grown in an open ocean 

aquaculture application by Snapperfarm in Puerto Rico. There has been one previously 

published NPV study of cobia (Posadas and Bridger, 2003). However, since then a great deal of 

information about cobia growth and culture has appeared. 

We built two conceptually similar models with assumptions that differ principally in the way in 

which productivity is estimated. In the first model we used 2003 data from Snapperfarm to 

estimate a total production of 3.78 kg/m3

 per year. Snapperfarm built its first two cages in 2002. 

Their target stocking density may not have been reached in 2003. Thus, adopting the fish density 

from the data reported in 2003 may underestimate the actual productivity of cage culture (Gulf of 
52

Mexico Fishery Management Council, 2007). To account for these potentially low production 

values, we developed a model in which we adjusted the initial stocking density and used per fish 

growth rates to determine production levels. Throughout the remainder of this chapter, we refer 

to the two models as model A and model B. We also considered pessimistic, optimistic and 

expected scenarios for both models. 

NPV is the difference between the present value of cash inflows and the present value of cash 

outflows. This measure is commonly used in capital budgeting to analyze the profitability of an 

investment or project and compares the value of a dollar today to the value of that same dollar in 

the future, taking inflation and returns into account. If the NPV of a prospective project is 

positive, it should be accepted; otherwise, the project should be rejected. The NPV equation is: 

 NPV = Investment Initial -

Capital) ofCost (1

Profit Net Annual t

1

⎥

⎦

⎤ ⎢

⎣

⎡

+ ∑=

T

t

 = Investment Initial -

t Capital) ofCost (1

Depreciati-Costs Operating - (Revenue Depreciati Rate)Tax -(1 on) on 

1 ⎥

⎥

⎦

⎤

⎢

⎢

⎣

⎡

+

× + ∑

=

T

t

 

6.2.1. Model Assumptions 

The assumptions of the models are listed in Table F.3. We model a hypothetical platform system 

with a variable number of 39,270 m3 cages. The system consists of a single platform which 

supports 2, 4, or 8 cages. We assume that there is no ongoing oil or gas activity, and that the 

aquaculture operator takes full responsibility for the platform and its associated liability. We 

assume that the number of workers scales linearly with the number of cages, and the capital costs 

associated with vehicles and vessels is constant. We assume just one manager and one 

supervisor regardless of the number of cages. We assume variable but high costs of capital 

commensurate with an unproven and high risk industry. We also assume variable yearly 

efficiency gains that decrease operating costs by a set percentage each year. A variable 

contingency capital cost is assumed which serves to increase capital costs by a small percentage 

in order to factor in overlooked capital expenditures. 

Data on cobia come from (Waldemar Nelson International, 2001; Posadas and Bridger, 2003; 

James and Slaski, 2006; Benetti et al., 2007; Hendrix, 2007; Keithly, personal communication, 

2007; Aquaculture Center of the Florida Keys, 2007; Benetti et al., 2008; BioMarine 

Technologies Company, 2000). We assume that cobia grows quickly, reaching 4 to 6.5 kg one 

year after hatching (GMIT, 2006; Aquaculture Center of the Florida Keys, 2007; Benetti et al., 

2008). A variable FCR of 1.3 to 1.7 is assumed. In both models the cobia are 20 grams upon 

stocking. Shipment of cobia fingerlings generally occurs at 1.5 grams, and there is a 20 day 

period between shipment and stocking in which cobia would be housed in tanks either on-shore 

or on the offshore platform. 

We assume that the operator is required to deposit $200,000 per year into an escrow account to 

cover decommissioning costs. Similarly, we assume an insurance cost of $200,000 per year and 

that the value of the infrastructure depreciates linearly with no salvage value. A feed price of 

1000 $/mt (Table F.4) and a variable cage cost described in Table F.5 are also assumed. 
53

6.2.2. Model A Calculations 

In 2003, Snapperfarm Inc used 2 Sea Station cages, each 3,000 cubic meters, to produce 50,000 

pounds fish (Gulf of Mexico Fishery Management Council, 2007). The production per cubic 

meter is approximately: 

3

3 /33.8

2000,3

000,50 mlbs

m

lbs = ×

( 3 /78.3 mkg )

In Model A, the production density is used to back calculate the number of fingerlings needed, 

given the basic model assumptions. The number of fingerlings needed per year is calculated by: 

Growth Annual The Species theof Rate

Yearper production Expected

SurviveRate

1

×

Feed cost is calculated as follows: 

 Feed Cost per Kg of Products = Uneaten -(1 Rate Survival Ratio) Feed

Feed of Kgper Price Ratio Conversion Food

×

×

The results of this calculation are shown in Table F.6. The total initial investment and annual 

operating costs and their components are shown in Tables F.7 and F.8, respectively. In the three 

scenarios, the feed and labor are the two most significant components of the operation costs, in 

total accounting for a share ranging from 44 to 63 percent. The remaining share is almost entirely 

fixed costs. Among the fixed costs, maintenance costs of equipment and the platform account for 

the largest portion, in total $530,000 per year, or approximately 20 percent of total operation 

costs. 

6.2.3. Model B Calculations 

In Model B, we stock the cages with a specified number of 20 gram fish. These fish grow to 

either 4, 5, or 6 kg in one year with a variable survival rate. The production is given by the 

formula: 

 Production (kg) = Number Fingerlings x Survival Rate x Average Final Weight (kg) 

In Model B, the feed requirements are calculated as: 

 Feed Requirements (kg) = Production (kg) * FCR

 (1- Uneaten Food Ratio) 

 

The total initial investment and annual operating costs and their components are shown in Tables 

F.7 and F.8, respectively. 
54

6.3. Results 

6.3.1. Model A Results 

Based on annual production and ex-vessel price, annual revenue can be calculated (Table F.9). 

Comparing estimated annual revenue to annual operation costs, we find that in the pessimistic 

and the expected scenarios the operating financial input cannot offset the output, indicating that 

the hypothetical platform-based operation will not be profitable over ten years. In the optimistic 

scenario, the estimated annual revenue is greater than the operation costs (compare Tables F.8 

and F.9). 

 

The NPV of our hypothetical platform-based mariculture operation are also shown in Table F.9. 

All NPVs of the three scenarios are negative. In pessimistic and expected scenarios, negative 

cash flows run through the entire operational life. Although in the optimistic scenario operating 

activities contribute a positive cash flow, this is inadequate compared to the initial investment to 

make NPV positive. The results indicate that, under the aforementioned assumptions, the 

investment on platform-based mariculture project is economically infeasible. 

 

6.3.2. Model B Results 

The results from Model B are significantly more positive than the results from Model A. In the 

expected and optimistic case the NPV is positive suggesting that platform-based cobia 

mariculture is economically attractive under these circumstances (Table F.10). Under optimistic 

assumptions, NPV is strongly positive with annual net cash flows (after taxes) of over $18 

million. With pessimistic assumptions, the model still generates positive net cash flows over its 

lifetime, but these cash flows are only $257,000 per year (before discounting) and not enough to 

make up for the $10.8 million initial capital expenditure. 

6.3.3. Rent Scenario 

 

Based on the expected Model A scenario, we developed a rent scenario to examine the economic 

feasibility when the hypothetical operation rents the necessary vessels and vehicles instead of 

purchasing them. This causes capital costs to decrease and operating costs to increase. The rent 

fees for every 10,000 tons production are assumed to be $2 million for vessels and $200,000 for 

vehicles. In the rent scenario, we also assume that the hypothetical operation receives a “free” 

platform from an oil and gas company, but that the mariculture operators are required to pay 

$200,000 per year towards decommissioning (alternatively, this could be understood as the 

mariculture operation renting a platform from an oil and gas operator for $200,000 per year 

without assuming decommissioning liabilities). 

The comparison of operation performances of the rent scenario and expected scenario are shown 

as Table F.11. In the rent scenario the hypothetical operation reduces its capital costs but 

increases operating costs to maintain its business. Although this operating strategy improves the 

NPV of the operation performance, it increases the operating costs and does not make the 

operation profitable. 
55

6.4. Limitations of This Analysis 

This analysis, like the analyses cited above, is limited by available data. There is little available 

data on fingerling costs, and feed prices had to be estimated from revenue and production data 

from major suppliers. Nonetheless, our assumptions are generally consistent with those of 

previous studies. 

 

It is difficult to find reliable information on the insurance premiums for offshore mariculture 

operations since commercial operations do not yet exist in the U.S. and since insurance 

premiums in the GOM region have increased significantly after Hurricane Katrina. The assumed 

insurance premium may be different from the real value. However, as illustrated in Table F.12, 

the NPV is relatively insensitive to changes in insurance costs. 

We did not include costs associated with growing fingerlings from their 1.5 g shipping weight to 

their 20 g stocking weight. Instead, we simply assumed the cost of the stocked fingerling was 

$2. Given the number of fingerlings required and the risk associated with shipment, it may be 

advantageous for cobia mariculturists to vertically integrate their operations, at least with respect 

to larvae hatching and growth. Fingerlings could then be grown to 20 grams onshore before 

transport to offshore cages. It is possible that this process could cost more than $2 per fingerling. 

However, using the break even analysis of model B we found that under expected conditions the 

price per fingerling would need to exceed $6.65 in order to make NPV equal to zero. Economic 

analysis of other fish species indicates that the costs of raising fingerlings may be well below $2 

(Kam et al., 2003), leaving significant money available to meet the costs of growing cobia to 20 

g over a 20 day period (Benetti et al., 2007). 

It is likely that the economic variables used in this analysis might change. Most importantly, the 

prices of harvested fish may either decline or increase depending on global trends and marketing. 

Between 1990 and 2005, the prices of fish and seafood raised by the aquaculture industry 

declined while the prices of most other seafood increased (Anderson and Shamsak, 2008). Thus, 

it is plausible to argue that cobia prices might increase as supplies from commercial fisheries are 

exhausted, or decrease if cobia production outpaces demand. Furthermore, open ocean 

aquaculturists could market their products as sustainable, thereby yielding higher prices. 

Finally, it is important to note the economies of scale assumed in the model. In general, the 

submerged cages used so far in open ocean mariculture projects are approximately 3000 m3

. The 

cages we envision are almost 40,000 m3 (a sphere with a diameter of 42 m). Ocean Farm 

technologies manufactures an AquaPod submersible cage with 9,800 m3 of volume (a sphere 

with a 27 m diameter), OceanSpar Technologies makes an AquaSpar cage with 40,000 m3 of 

space and the Grace Mariculture project envisioned using 125,000 m3 cages (Gulf of Mexico 

Fishery Management Council, 2007). However, it does not actually matter what sized cages are 

used in our models; as long as the total cage volume and the cost per m3 are constant, our model 

will yield similar results for 10 4,000 m3 as for one 40,000 m3

 cage. 
56

6.5. Discussion 

Table F.12 shows the points at which the NPV of Model A and B is equal to zero for selected 

parameters. In each case, we changed a single parameter and left all others at their default levels. 

As illustrated in the table, small changes in a variety of factors can make the Model A optimistic 

scenario profitable. Conversely, small changes in a number of parameters can make the Model B 

expected scenario unprofitable. 

Table F.13 and Figure F.1 illustrate the sensitivity of the model. Table F.13 compares the 

sensitivity of model B to changes in parameter values by comparing the change in NPV per unit 

change in parameter values. It is clear that the model is very sensitive to initial stocking 

densities. This is also seen in Figure F.1. 

In commercial aquaculture operations there is likely to be a tradeoff between FCR, stocking 

density, growth rate and survival rate. As operators increase stocking density, FCR will increase 

while growth rate and survival will decrease. Figures F.2 through F.4 delineate the break even 

points between stocking density and FCR, growth rate and survival using Model B, expected 

case. In each case the relationships are non-linear with large changes in the slope of the 

relationship around a stocking density of 0.1, the density chosen in the expected case of this 

model. This demonstrates the precarious nature of investment in offshore aquaculture. 

Additionally, the graphs show the more positive opportunities associated with higher stocking 

densities. If mariculturists can increase stocking densities to 0.2 to 0.3 kg/m3

 then there is much 

greater opportunity for positive NPV. 

Of the six models discussed in this paper, the pessimistic case of model B may be the closest to 

the current reality for offshore cobia culture. In 2007, Snapperfarm produced 100 tonnes of 

cobia using approximately 9,000 m3 of cage volume (Benetti et al., 2008). The total density 

would have been 11.11 kg/m3

 comparable to the density of 15 kg/m3 used in the pessimistic case 

of Model B. Importantly, Snapperfarm operates at a much smaller scale than our hypothetical 

model. This combined with the negative NPV associated with the Model B pessimistic case 

suggests that cobia culture may not be economically feasible. 

6.6. Conclusions 

Our analysis illustrates the sensitivity of platform-based mariculture to changes in stocking and 

production density. The primary differences between Models A and B are in the way in which 

production is calculated. In Model A, production is based on empirical data, but we suspect the 

data may not represent the true situation due to the nascent nature of the industry. Conversely, 

production in Model B is based on theoretical growth and survival data, with stocking densities 

chosen to produce realistic final densities. These densities are 5 to 10 times the final densities 

used in Model A and the results from Model B give a much rosier picture for the future of 

offshore platform-based mariculture. 

Platform-based offshore mariculture carries significant risks. Our models indicate operations 

may or may not be profitable depending on the assumptions used. The assumptions that we used 

generally cover the range of expected real values. Thus, investment in offshore mariculture is 
57

risky. If the early attempts at offshore cobia mariculture can demonstrate yields of over 20 kg 

per cubic meter of cage volume then the chances of a commercially successful venture grow 

significantly. 

 

 
59

7. COMPARISON OF OFFSHORE WIND POWER DEVELOPMENT IN EUROPE AND 

THE U.S.

In the U.S. there has been significant interest in the development of an offshore wind energy 

industry. Increasing coal, natural gas and oil prices, an increasing reliance on foreign sources of 

oil, and increasing concerns about global climate change, have made domestic, renewable and 

low carbon sources of energy particularly attractive to policy makers. As of mid 2009, no 

offshore wind farms are under construction in the U.S., but resource assessments are ongoing at 

Cape Cod, Massachusetts, and Galveston, Texas. 

We begin this chapter with a discussion of the patterns of offshore development in Europe and 

compare to the proposed developments in the U.S. We discuss the current status of offshore wind 

plans and testing in the U.S. and reasons for the cancellation of some projects. The policy 

drivers of the offshore wind energy industry in Europe are compared to the drivers in place in the 

U.S. We conclude with a discussion of the effects of potential U.S. policies on the offshore wind 

industry. 

7.1. Introduction

Wind energy is the alternative energy source with the most realistic chance to displace large 

amounts of fossil fuel combustion. Over the past several years, the onshore wind energy 

industry has seen explosive growth, both in the U.S. and around the world (Figure G.1). In 

Europe, the growth in the onshore wind energy industry has been supplemented with growth in 

the offshore industry (Figures G.2 and G.3) which at present represents 1.8 percent of the total 

installed European wind capacity.16 The first offshore wind farm began operating in 1991; by 

the end of 2007 there were approximately 1,200 MW of installed capacity. By 2009 the wind 

capacity in Europe is expected to grow by another 1,500 MW, and by 2015, the rate of growth of 

the European offshore industry is expected to be 1,700 to 3,000 MW per year (EWEA, 2007). 

 

There are a number of reasons why offshore wind development has lagged behind in the U.S. 

Both the offshore wind resources and the governmental subsidies for offshore wind power differ 

in Europe and the U.S., and it is not clear if offshore wind power will be profitable in the U.S. in 

the short term. In general, wind speeds increase further from shore. This increases the electrical 

generation of turbines, but operating in the offshore environment is significantly more expensive 

and risky than onshore, and for offshore wind development to succeed, a combination of events 

must hold. The revenue potential from offshore wind must exceed the associated costs and risks, 

federal involvement in advancing renewables through regulatory programs and economic 

incentives must be in place, state involvement through renewable portfolio standards must 

continue, and public acceptance of offshore wind farms must occur. 

 

 

16 Due to the higher wind speeds over the ocean, offshore wind generates a disproportionate percentage (3.3 percent) 

of the wind generated electricity in Europe (EWEA, 2007). 
60

7.2. Offshore Wind Energy Development in Europe 

 

7.2.1. European Wind Farms 

There are a number of operational (Table G.1) and approved but not constructed offshore wind 

energy projects in Europe (Table G.2). Denmark and the UK have the largest share of 

operational offshore capacity. Germany has the largest share of planned capacity, but has no 

significant operational wind farms (Table G.3). 

 

7.2.2. Trends in Europe 

One of the clearest trends in the offshore wind industry in Europe is the increasing size of wind 

farms (Figure G.4). Additionally, developments have progressed into deeper water, further from 

shore and have adopted larger turbines (Figures G.5 - G.7). 

 

In Europe, developers and nations began by developing relatively small test projects (10 to 50 

MW), then developments of 100 to 200 MW, and are now building or planning projects of 400 to 

1,000 MW (EWEA, 2007). This slow development has been intentional and has occurred 

primarily due to government planning; however, the large farms currently being planned may 

allow for large cost reductions through scale economies. 

 

The deepest offshore turbines constructed to date have been at Beatrice where turbines were 

constructed on jacketed foundations in 45 m of water. Excluding Beatrice, the deepest offshore 

wind farms have been built in water only 10 to 20 m deep, due largely to the constraints of 

monopole and gravity foundations. Floating wind turbines are being tested in Italy which would 

allow for development in water over 100 m deep. 

 

The wind farm farthest from shore is Thornton Bank which is 27 km from the Belgian coast. In 

the near future the Belwind wind farm will be built over 40 km from the Belgian coast. While 

both Thornton Bank and Belwind are connected with AC cables, the costs of DC transmission 

are declining which will allow for development further from shore. 

 

The turbine capacity used in both onshore and offshore wind farms has increased over the past 

decade. Larger turbines are thought to allow for lower operation and maintenance costs, 

installation, and foundation costs per unit of capacity. The largest turbines used so far have been 

5 MW built by REPower and were used in Beatrice and Thornton Bank. However, Enercon has 

installed a land based 6 MW turbine and Clipper Windpower is planning on building a 7.5 MW 

turbine. 

 

It is both technologically and economically possible that the next decade will see turbines of up 

to 10 MW, dozens of kilometers from shore on floating foundations in over 100 m of water. 

 

7.2.3. Industry Structure 

European wind farms have been developed by some of the largest energy companies in Europe 

including Vattenfall (Sweden), Shell (Netherlands), DONG (Denmark), Nuon (Denmark), E.ON 
61

(Germany), and Centrica (UK). Shell, DONG, and Centrica are integrated energy companies 

that are involved in both electricity generation and oil and gas exploration. Nuon and E.ON are 

electricity and gas providers, Vattenfall is an electricity provider owned by the Swedish state but 

active in much of Northern Europe. 

 

In addition to these large energy companies, a few companies specializing in renewable energy 

have also developed offshore wind farms; however, these companies are generally subsidiaries 

of large electricity and gas companies. Airtricity, a wind farm developer and subsidiary of a 

large electricity and gas provider Scottish and Southern Energy, has developed the Arklow Wind 

farm. Npower Renewables, a developer of wind, hydroelectric and biomass power facilities and 

a subsidiary of RWE, developed the North Hoyle wind farm. Evelop, a subsidiary of Econcern 

and a company specializing in the development of renewable power plants, developed the Q7 

wind farm and is developing the Belwind Wind Farm. 

 

7.2.4. System Configurations 

Most offshore wind farms in Europe have been set up in grid configurations with several 

hundred meters between adjacent turbines (Figure G.8). However, Middelgrunden was arranged 

in a single curved line (Figure G.9), and Horns Rev II will be arranged in a series of seven radial 

lines (Figure G.10). The configuration and design of an offshore wind farm depends on a 

number of technical factors such as the size of the wind farm, the wind speed, the wake effects of 

the turbines, the number of turbines, the dominant direction of the wind, the cabling costs, and 

aesthetics (Manwell et al., 2002). 

The turbines in offshore wind farms are almost always linked together with 30 to 36 kV 

electrical connections. They are then linked to an electrical service platform (ESP). The ESP 

increases the voltage to over 100 kV for transmission to shore (Figure G.11). 

 

In the future, operators will also have to decide whether or not to permanently man offshore 

wind farms. So far, this has not been economical given the small size and proximity to shore. 

However, if wind farms are located a long distance from a port facility and require large amounts 

of daily maintenance, then developers may decide to staff the wind farms. The Horns Rev II 

wind farm is expected to be a manned facility. 

 

7.2.5. Installation 

Marine construction companies fabricate and install offshore wind farms. Installation is 

accomplished using jack up barges for pile driving and lifting (Figure G.12). Often several boats 

are active simultaneously so that one boat is pile driving while another is installing towers or 

turbines and another may be ferrying equipment from port to the site. 

 

Construction companies have attempted to minimize the work done offshore by assembling as 

much of the turbines onshore as possible. This speeds the expensive offshore work and reduces 

the number of lifts required for construction. Among the most common techniques for 

minimizing offshore work is to connect two of the turbine blades to the nacelle on land “bunny 

ear” configuration and lift them together onto the tower (Figure G.13). 
62

The most extreme onshore assembly to date has occurred at Beatrice where a jacketed foundation 

was assembled onshore and towed to location and sunk in place (Figures G.14 and G.15). The 

entire turbine and tower were assembled onshore, floated to the site, and connected to the 

foundation (Figures G.16 and G.17). 

 

Seventy-five percent of the offshore turbines have been installed by the Danish company A2SEA 

including the turbines at Q7, Lillgrund, Nysted, Horns Rev, Egmond aan Zee, Kentish Flats, 

Scroby Sands, and Fredrishavn. A2SEA was formed in 2000 with the specific goal of providing 

construction services to the offshore wind industry. It currently operates 3 specially equipped 

jacking boats. While it has installed a number of turbines, it has generally not installed 

foundations. 

 

In other cases, companies that do not specialize in the offshore wind power industry have been 

used for installation projects. For example, the North Hoyle and Beatrice projects used the 

companies Seacore and Scaldis, respectively. Both of these companies are marine construction 

companies with experience in the oil and gas and civil works industries. Seacore has also been 

involved in the construction of foundations, met masts and geotechnical surveys for a number of 

other offshore wind projects. 

 

Larger international companies have also installed some wind farms, but their work seems to be 

limited to the foundations. For example, HOCHTIEF installed the foundations for the Lillgrund 

wind farm while Van Oord installed the foundations at Q7 and KBR installed the foundations 

and electrical connections at the Barrow wind farm. 

7.2.6. Foundations 

European developers have been cautious with the application of new technology. Despite having 

a number of development options, wind farms have been built in nearly identical ways. Most 

offshore wind projects in Europe have used either gravity foundations (Figure G.18) or 

monopiles (Figure G.19) as foundations. There have been a few experimental projects that have 

used jacketed foundations or suction caissons, though these have not been used at a commercial 

scale. Most projects have used monopiles and only choose gravity foundations where subsea 

conditions do not allow pile driving. When developers decide to test new technology, they do so 

at very small scales, for example, the Beatrice and Fredrickshavn projects. 

 

7.3. U.S. Development 

There are two offshore wind farms that are currently in the late planning stages in the U.S., Cape 

Wind and Galveston Offshore Wind. There have been several others that began planning and 

development at roughly the same time as these two developments, but have since been cancelled 

due to economic reasons. These include the Long Island Offshore Wind Park and the Padre 

Island Wind Park. In each case, the developer or utility decided that there were cheaper ways to 

generate renewable energy. Table G.4 describes the planned and cancelled developments in the 

U.S. 
63

7.3.1. Cape Wind 

The Cape Wind project is the best known and most controversial wind project in the U.S. Cape 

Wind and its opponents have been featured in national media including the CBS News, The New 

York Times, and NPR. Originally proposed as the nation’s first offshore wind farm in 2001, its 

development has been delayed by opposition by local and powerful activists including Walter 

Cronkite, Mitt Romney and the Kennedy family. 

 

Energy Management Incorporated (EMI), the developer of the Cape Wind project, plans to place 

130 3.6 MW turbines approximately 6.5 miles off the coast of Cape Cod in an area called 

Horseshoe Shoal (Figure G.20). The 130 turbines will be manufactured by GE and will be 

arranged in a grid-like pattern. The total footprint of the site will be 25 square miles (70 km2

). 

The hub height will be 78.5 m which will ensure a clearance of 23m between sea level and the 

blades’ lowest position. The turbines will be placed in shallow water, between 0.15 and 18 m 

deep (USDOI, MMS, 2008a). 

 

The Cape Wind project is in the final stages of approval. Under the 2005 Energy Policy Act, the 

BOEMRE completed an Environmental Impact Statement (EIS) which found negligible or 

minimal impacts on wildlife or navigation. BOEMRE has given its regulatory approval in early 

2009. According to EMI, the Cape Wind project could be operational by 2011 (EMI, 2008). 

 

7.3.2. WEST 

Wind Energy Systems Technologies (WEST) is a Louisiana based company that is planning on 

building a series of wind parks in state waters off the coast of Texas. Unlike most other states, 

Texas’ state waters extend 3 marine leagues (9 nautical miles) from the shore. As a result, 

WEST is required to negotiate leases and permits only with the State of Texas, and is not under 

BOEMRE jurisdiction. Nonetheless, WEST will still have to apply for a Rivers and Harbors Act 

Permit. 

WEST has negotiated to lease 11,000 acres of submerged land from Texas for the next 30 years. 

The lease is for an area approximately 7 miles off the coast of Galveston. The lease requires 

WEST to pay the State at least $26 million over the course of the 30 year lease. WEST has 

placed two meteorological observation towers on the lease. Their plan is to build a 150 MW 

wind farm at a cost of about $300 million (Schellstede, 2008). WEST submitted a Rivers and 

Harbors Act permit in late 2008. WEST has also signed leases with the state of Texas for four 

additional tracts off the coast of south Texas. 

WEST has investigated a number of engineering concepts for building offshore wind farms in 

the Gulf of Mexico. They had originally planned on placing wind turbines directly on unused oil 

structures in the Gulf of Mexico without removing and relocating the structures; however, they 

seem to have abandoned this plan (Schellstede, 2004 and 2008). They then planned to use a 

jacked platform recycled from the oil industry as a foundation for their wind turbines and hoped 

that this would save the company money and make their operation profitable (Geoghegan, 2007). 

They have also planned to install some type of jack system which will lower the turbines in the 
64

event of a hurricane. Most recently, they have opted for installing the turbines on tripod 

foundations (Schellstede, 2008). 

7.3.3. Bluewater Wind 

Bluewater Wind is a subsidiary of Babcock and Brown. They are in the planning stages for 

constructing a large wind farm off the coast of Delaware. In November 2006 Delmarva Power, 

in response to actions by the Delaware legislature, issued a request for proposals for the 

construction of a new power plant in Delaware. Bluewater Wind submitted a proposal for a 450 

MW wind park located 11.5 nautical miles (21 km) from the shore and was selected to negotiate 

a power purchase agreement in May of 2007. They estimate that it will take one to two years 

for construction to commence and an additional one to three years to complete construction 

(Bluewater Wind, 2008). 

 

Delmarva Power has stated that they are more interested in onshore wind than offshore wind 

power and that they believe onshore wind power will be less expensive for Delaware consumers 

than offshore wind power (Benson, 2008). They also believe that onshore wind power will be 

ready more rapidly. Delmarva Power solicited bids from other power producers, but in the 

summer of 2008, Delmarva Power and Bluewater reached an agreement on the terms of a 

contract (Nathans, 2008) which was then accepted by the State and the project may now move 

forward. 

 

7.3.4. Deepwater Wind - Plum Island Wind Park 

Deepwater Wind (formerly Winergy Power LLC) was formed in 1999 by a former offshore 

mariculture executive. Deepwater is developing a test site off the Northern Fork of Long Island 

called Plum Island Wind Park. This development is meant to be a small-scale research facility; 

however, they are also evaluating the placement of larger projects off the east coast of the United 

States from Massachusetts south to Maryland. 

 

The Plum Island Wind Park is designed to consist of three, 3.6 MW turbines or two, 5 MW 

turbines. The closest turbine would be 1,500 feet off of Plum Island in Gardiner’s Bay and the 

turbines would be approximately 1,000 m from each other. At least one turbine (and perhaps 

two) will be installed on a monopile foundation while one other turbine will be installed on a 

tripod jack-up barge foundation. Deepwater intends to tow an assembled wind turbine into place 

on a jack up barge and leave it in place. 

 

Deepwater has applied for a Rivers and Harbors Act permit from the Army Corps of Engineers. 

The public comment period closed in August 2007 and Deepwater is responding to these 

comments. Deepwater has also been selected as the winning bidder for projects off the coast of 

Rhode Island and New Jersey. 

 

7.3.5. LIOWP 

The Long Island Offshore Wind Park was a project proposed by the Long Island Power 

Authority (LIPA). In January 2003, LIPA issued a request for proposals to develop an offshore 
65

wind farm. FPL Energy, one of the nation’s largest providers of wind and solar power, was 

selected. In 2007, the project was cancelled, citing economic reasons.17 The LIOWP would have 

consisted of 40, 3.6 MW GE turbines with a combined capacity of 144 MW and 3.6 miles from 

Jones Beach on Long Island’s southern side. As in the Cape Wind project, the LIOWP was 

opposed by some residents who feared that it would intrude on the aesthetics of the community. 

 

7.3.6. Babcock and Brown - Padre Island Wind Farm 

Babcock and Brown is an Australian investment firm with a large alternative energy portfolio. 

In August 2006, Babcock and Brown bought Superior Renewable Energy (SRE), a Houston 

based company that had planned on building a wind farm off the coast of Padre Island, Texas. 

SRE had leased the rights to 39,900 acres of submerged lands off the coast of Kenedy County 

and had planned to build a 170 turbine, 500 MW wind farm. The lease allowed for a four-year 

research period followed by construction and required annual payments of $80,000 plus a 

percentage of future earnings (Porretto, 2007). However, in June 2007, Babcock and Brown 

cancelled the lease saying it was “too expensive to produce energy that way in that market” 

implying that the price of electricity in Texas made it difficult for its project to be profitable. 

Babcock and Brown are currently developing onshore wind farms in Texas. The Texas General 

Land Office still hopes to develop the site (Porretto, 2007). 

 

7.3.7. South Coast Wind 

Patriot Renewables, LLC, has developed a plan to build an offshore wind farm in Buzzards Bay, 

Massachusetts. They submitted their plans to the Massachusetts Office of Environmental Affairs 

in May of 2006. Called South Coast Wind, their plans call for 90 to 120 turbines placed in up to 

three separate groups. The total capacity will be approximately 300 MW; however, the exact 

size turbine has not been determined. Each group will be within 3 miles of the shore in under 20 

m of water. Therefore, a BOEMRE lease will not be required (Patriot Renewables, 2009). 

The Secretary of the Office of Environmental Affairs of Massachusetts ruled that an 

Environmental Impact Report (EIR) under the Massachusetts Environmental Policy Act (similar 

to an EIS under NEPA) was necessary. Patriot Renewables is currently conducting the 

environmental analyses called for by the EIR (Patriot Renewables, 2009). 

 

7.3.8. Proposals to BOEMRE 

In November 2007, BOEMRE asked for nominations for areas to be leased for offshore wind 

energy, and other ocean energy development. They received over 40 nominations for resource 

evaluation leases. BOEMRE has decided to proceed on leasing 10 blocks, each 9 square miles 

for offshore wind evaluations. Five of these areas are off New Jersey, three are off the coast of 

Georgia and one is off the coast of Delaware. BOEMRE also received interest in wind leases off 

New York, South Carolina and Massachusetts, but decided not to proceed with leasing these 

tracts partly because the areas desired for leasing were sought by more than one developer. To 

 

17 LIPA commissioned a study conducted by PACE Global Energy Services to evaluate the costs of the proposed 

wind park. They estimated construction costs to be $4841/kW, far higher than previously anticipated or experienced 

(PACE, 2007). 
66

lease under such circumstances would involve competitive leasing and would be taken up by 

BOEMRE only after promulgation of the regulation controlling development of offshore 

alternative energy projects (Federal Register, 2008b). 

7.4. Patterns of Development 

The plans for U.S. wind farms are different from the first offshore wind farms built in Europe. 

In the U.S., developers are not planning small 10 to 50 MW developments, but much larger 

projects of hundreds of MWs. There are only two small test projects under consideration. The 

advantage of the European pace of development was that it allowed for the development of 

infrastructure, institutional capacity and experience. 

 

American projects are also not limited to shallow water close to shore, as were European projects 

in the early stages of development. WEST is planning on building its offshore wind farm in 

relatively deep water while Bluewater Wind is planning on building its Delmarva Wind Park 

over 20 km from the coast (Bluewater Wind, 2008). 

 

The developers of the larger offshore wind projects in Europe are among the largest energy 

companies in Europe. Conversely, in the U.S., relatively small and newer companies (WEST, 

Deepwater Wind, and EMI), are planning on building wind farms that may cost close to $1 

billion. There has been some interest among large energy companies in the U.S. in offshore 

wind development, most notably Southern Company and FPL Energy (USDOI, MMS, 2005a), 

but the most promising developments (the Galveston and Cape Wind projects) are being led by 

companies without the large capital and institutional experience of the larger energy 

conglomerates. The construction of an offshore wind farm requires a large amount of capital 

and would be seen by investors as a high risk investment. As a result, investors would require 

high interest rates. The federal government will likely require some type of surety bond to 

guarantee the removal of the facilities after the term of the lease. It will be far more difficult for 

small companies to acquire these bonds and it is likely that they will need to be heavily 

collateralized. Again, this will increase the costs of offshore wind farms. 

 

American developers do not have ready access to the specialized construction equipment 

available to European companies, such as that developed by A2SEA and Seacore, but in the Gulf 

of Mexico significant expertise and construction equipment used in the offshore oil industry can 

be utilized. If marine construction equipment is limited, it will cause the costs of construction to 

increase. It is possible that global companies, for example KBR and HOCHTIEF, may also 

contribute to the development of wind farms in the U.S. 

 

It is possible that the lack of companies with direct wind farm installation experience could 

increase the expense of development. Construction costs are sensitive to the amount of time it 

takes to install each turbine. In general, these construction times decline as an operator gains 

experience.18 It therefore seems likely that companies with offshore wind farm installation 

experience would be able to complete installation more quickly than companies without 

experience. 

 

18 For example, the first foundations at North Hoyle required 132 hours to install while the last foundations took 

only 67 hours to install (Carter, 2007). A similar trend occurred at Horns Rev (Junginger et al., 2004). 
67

In general, developments in the U.S. will use many of the same construction techniques that have 

been employed in Europe, but there are some important differences, especially in foundation 

types. WEST is planning on using a tripod foundation and Deepwater Wind is planning on using 

a three-legged self jacking foundation. Both of these are novel foundations and in both cases the 

companies involved plan on establishing test turbines before developing full wind farms 

(Schellstede, 2004 and 2008; Deepwater Wind, 2009). 

 

Offshore wind farms are capital intensive; they can cost over $1 billion and generate little 

revenue for years. In Europe, large international energy companies have been the primary 

developers of offshore wind farms. In the U.S., this has not been the case. There are a number 

of advantages for large corporations over smaller start-ups in the development of offshore wind 

farms. Large corporations will have more available capital and will be able to raise additional 

capital at lower interest rates; large corporations will have less difficulty securing surety bonds 

and may not require decommissioning bonds; large corporations would be able to spend more 

time planning projects and testing new technology without the need to quickly generate revenue; 

and large energy companies would gain the positive environmental publicity associated with an 

offshore wind farm, something of less value to a company that specializes in offshore wind 

energy. Finally, a large company may be able to build a large number of offshore wind farms 

and thereby gain the institutional experience required to lower costs. A smaller company that 

has developed one wind farm, even a successful wind farm, would be heavily indebted and may 

be unable to raise the capital necessary to build additional wind farms. Thus, while small 

companies like WEST, and EMI may indeed build the first offshore wind farms in the U.S. and 

be successful, it is likely that offshore wind power will be developed at a large scale when 

companies like Southern Company, Babcock and Brown, and FPL Energy become committed to 

offshore wind energy. 

7.5. Causes of Differences in European and U.S. Industries 

Over the last decade, the costs of producing wind power have dropped dramatically while the 

costs of conventional sources of electricity, especially oil and natural gas have risen significantly 

(Wiser and Bolinger, 2008). This has stimulated growth in the wind industry in general in both 

Europe and around the world, but it has failed to stimulate the offshore industry in the U.S. This 

failure is due to a number of factors including different financial incentives, regulatory systems, 

wind resources, population densities and industry representation. 

 

7.5.1. Financial Incentives and Subsidies 

Every nation in Western Europe is an Annex 1 party to the Kyoto protocol and as such is 

mandated to reduce their carbon dioxide emissions. The nations of Western Europe have 

responded by setting mandates for the amount of electricity produced from renewable sources by 

specific times. In order to meet these goals, European nations have instituted a series of financial 

incentives (Table G.5). The primary mechanisms of financial support for renewable energy are 

through tax credits, feed-in tariffs, renewable energy credits, or tenders (Reiche and Bechberger, 

2004). 

 
68

The exact cost of a kWh of offshore wind produced electricity varies depending on the specifics 

of the wind farm; estimates range from 5 to 12 ¢/kWh (Fingersh et al., 2006; Dept. for BERR, 

2004; Mense, 2007). Thus, a wind farm developer has to be able to reliably sell electricity for 

more than 5 to 10 ¢/kWh in order to make a profit. The easiest way for a developer to do so 

would be to negotiate a feed-in tariff, as is done in Denmark. The feed-in tariff is thought by 

renewable energy advocates to be the most beneficial method of renewable energy promotion, 

but it is not clear if this is actually the case (Reiche and Bechberger, 2004). In the case of Danish 

feed-in tariffs, the developer submits a bid to build an offshore wind farm at a certain feed-in 

price, thereby ensuring that the operation is, at least according to their plans, profitable. An 

alternative method for incentivizing renewable energy is through the use of a renewable energy 

credit market. This is the primary means of providing financial incentives in the UK. Many 

nations in Europe also have carbon taxes from which renewable energy generators are exempt. 

Finally, in the UK the government will give offshore wind developers grants to help pay for the 

capital costs of offshore wind farms. So far, $194 million has been divided among 10 projects 

(Dept. for BERR, 2008). Given that the costs of these wind farms have been in the hundreds of 

millions of dollars, this represents a small, but not insignificant, fraction of the total capital costs. 

 

In the U.S., the primary federal mechanism for the stimulation of renewable energy is the 

Production Tax Credit (PTC). The PTC is analogous to a bonus feed-in tariff, or a carbon tax 

exemption. It is a 2 ¢/kWh tax credit for companies that produce electricity from certain 

renewable sources (including wind). It has expired three times over the last ten years; each time 

it has expired has been associated with a decrease in the growth of the onshore wind industry 

(Vann, 2007). This suggests that it is an important stimulant for the wind energy industry. 

The U.S. federal government does not have a renewable energy credit trading scheme; however, 

twenty-five states and the District of Columbia have adopted Renewable Portfolio Standards 

(RPS) requiring that a certain percentage of the state’s electricity be generated from renewable 

sources (DSIRE, 2008). RPS requirements generally range from 10 to 20 percent of production. 

Utilities that fail to meet these requirements must purchase tradable credits that represent an 

equivalent amount of renewable energy (renewable energy credits, REC) or face penalties of up 

to 5.5 cents per kWh. 

Given that the largest penalties for non-compliance with RPS goals is 5.5 ¢/kWh, and that the 

federal PTC is 2 ¢/kWh, the total state and federal subsidy for offshore wind energy is at most 

7.5 ¢/kWh. In most cases the actual subsidy will be much lower due to lower prices for RECs. 

For example, in Texas the cost of a REC in 2007 was 0.5 ¢/kWh. Even at the upper limit for 

RECs, the subsidies for offshore wind energy in the U.S. are significantly lower than those in 

Europe. For example, in the UK the tax exemptions and RECs amount to 18 ¢/kWh. 

 

In the U.S. in 2007, the average wholesale price of electricity was about 6 ¢/kWh (Wiser and 

Bolinger, 2008). Including revenues from RECs and the PTC, wind farm operators may be able 

to sell electricity for 8 ¢/kWh. This is within the range of the costs of offshore wind power; 

however, the profitability of a particular farm will depend on the local energy market and capital 

costs of the wind farm. 

 
69

In addition to being smaller, subsidies in the U.S. are less certain than those in Europe. The PTC 

could expire and REC prices are not set at minimum levels. Thus, unlike in Denmark where 

developers are guaranteed a certain price, developers in the U.S. are taking a significant risk in 

developing an offshore wind farm and are, in essence, gambling that REC prices increase and the 

PTC is renewed. 

 

Recently, the U.S. Department of Energy (DOE) instituted a program in which it will guarantee 

private loans for up to 80 percent of the total project costs made to renewable energy developers 

(USDOE, 2008b). Guarantees may exceed $500 million, but may be made only for technologies 

that are not in general commercial use (are not operating in more than three facilities for more 

than 5 years). These loan guarantees should make financing offshore wind projects more 

feasible, but unlike European programs, do not provide direct grants for capital expenditures. 

7.5.2. Regulations 

The governments of Western Europe have instituted regulations specifically for expediting and 

encouraging offshore wind energy. In Denmark the government issues tenders for offshore wind 

farms in which developers compete to offer the government the lowest feed-in price for a given 

development (DEA, 2007 and 2008). This central planning has almost certainly sped 

development. In the UK, the Crown Estate has held two rounds of leasing which have provided 

an expedited system of approval. In the most recent round the government identified areas for 

development and conducted environmental studies before leasing (The Crown Estate, 2008). In 

Germany, approval of wind farms was made non-discretionary; wind farm developers have a 

right to build wind farms unless the government decides that they pose a threat to navigation or 

the environment. Furthermore, in both Germany and the Netherlands, competition is based on a 

first-come-first served process in which developers compete to be the first to submit an 

acceptable application for a given area (BSH, 2008). This could encourage speculative claims, 

but would also encourage developers to quickly apply for developmental rights. 

 

The U.S. currently lacks a final regulatory system for offshore wind energy, and the development 

of a regulatory system has been slowed by legal challenges, Congressional action and detailed 

planning on the part of regulators. Therefore, despite the fact that the first offshore wind farm 

was proposed in U.S. waters in 2001, as of July 2008, it has not been approved. Conversely, 

many European wind farms have begun operation within 4 or 5 years of being proposed. 

 

Regulations stipulate the fees that developers must pay for use of the seabed. The fees that 

European nations charge for use of the seabed are either minimal or nonexistent and they are 

almost never competitively determined (DEA, 2007 and 2008; The Crown Estate, 2008; BSH, 

2008). The proposed U.S. regulations include modest royalties for use of public lands that are 

based, in part, on competitive bidding for the proposal with the largest monetary benefit to the 

state (Table G.6). The presence of these fees will have an effect on the profitability of wind 

farms in the U.S.; however, their impact will be dwarfed when compared to the differences in 

subsidies offered in Europe and the U.S. 

Some other differences in regulatory structure that may impact development are given in Table 

G.6. It is possible that the long leases of the UK system or the site selection by regulators in the 
70

UK and Denmark could have sped development in these countries (Concerted Action for 

Offshore Wind Energy Deployment, 2005). 

 

7.5.3. Wind Resources 

One of the most critical reasons for the development of the offshore wind industry in Europe is 

the larger number of suitable sites. In general, wind speeds increase further from shore. This 

increases the electrical production of turbines, but the additional distance also increases their 

cost. The challenge for developers is to find sites that have high winds but are close to land and 

in shallow water. There are a number of sites off the coast of northern Europe where wind 

speeds average 9 to 10 m/s at 50 m (Figures G.21 and G.22). These wind speeds are considered 

superb by NREL for wind energy production. In contrast, the winds off the coast of New 

England are generally 8 to 9 m/s while those in the Gulf of Mexico are 7 to 9 m/s. The Pacific 

coast does have areas of 9 to 10 m/s winds, but these are generally in deepwater. There are 

small areas of high winds and shallow waters off the coast of New England (Figure G.23). 

These sites are likely as suitable as those in Europe. Even the more modest winds of the Gulf of 

Mexico can be developed; however, they are likely to have lower capacity factors and therefore 

lower revenues. 

 

7.5.4. Population Density 

 

Population density is an overlooked driver of offshore wind development. Due to the high 

population density of Europe, Europe has less room to expand onshore wind energy production 

(Ackermann and Söder, 2002). Much of Europe is densely populated, including Denmark, the 

UK and Germany, the countries that have seen the most offshore wind development (Figure 

G.24). This high population density effectively forecloses increased onshore wind development, 

often the cheapest renewable energy source. 

 

Conversely, the wind resources of the U.S. are concentrated in the Midwest where population 

densities are low, thus there is ample room for expansion of onshore wind resources without 

significant conflicts with local populations (Figures G.23 and G.25). U.S. developers interested 

in wind development can therefore develop cheaper and less risky projects onshore without the 

need to go offshore. 

 

In general, the populations of both the U.S. and Western Europe have similar attitudes towards 

local offshore development. As in the U.S., local residents in Europe are willing to pay to keep 

wind farms out of their viewshed. In the U.S., Haughton et al. (2003) estimated the willingness 

of Cape Cod residents to pay for not placing wind farms in their area to be $75 per person, while 

Ladenburg and Dubgaard (2007) estimated a similar value at approximately 120 Euros ($190) 

for Danes.19 Although the results are not directly comparable, they do suggest that in both places 

citizens place a modest premium on viewsheds unobstructed by wind turbines. 

 

 

19 In the Danish case the willingness-to-pay was estimated on a per household annual basis, while in the U.S. study, 

payments were assumed to be one time and per person. 
71

7.5.5. Commercial Interests 

Europe is home to some of the largest producers of wind turbines including Siemens, Enercon, 

Gamesa, Vestas and Repower (Table G.7). Similarly, Europe is the primary source for 

submarine transmission cables used in offshore wind farms (Wright et al., 2002) and has a welldeveloped offshore construction industry associated with the North Sea oil and gas industry. As 

a result, each offshore wind development has a cascading impact on jobs throughout the 

European economy providing jobs in the offshore construction, turbine, and cable industries, as 

well as the companies that support those industries, especially banks and steel manufacturers. 

 

European legislators, especially in Denmark and Germany, have an incentive to aid in the 

development of markets for wind turbines and European companies can put pressure on 

legislators to encourage wind farm development. Conversely, in the U.S. offshore turbines may 

or may not be made in the U.S. and the marine cable almost certainly will not be. (Wright et al., 

2002). Thus, the number of jobs created per MW of offshore wind capacity will be lower in the 

U.S. than in Europe. Furthermore, the major U.S. wind turbine manufacturer, GE, is not 

primarily a wind turbine company (unlike Vestas or Enercon) and GE profits, and thus its 

lobbying effort, will only be marginally impacted by an offshore wind industry. 

7.6. Potential Policies for Increasing Offshore Wind in the U.S. 

There are a number of policies which could be adopted by the U.S. that could stimulate the 

offshore wind industry (Bird et al., 2005). It is unlikely the U.S. will mimic successful European 

policies like feed-in tariffs; it is more likely to implement market driven policies (Birgisson and 

Petersen, 2006) and policies similar to those it already has some experience with. Here, we 

discuss the potential impacts of four policies on offshore wind energy. We discuss the effects of 

a federal renewable portfolio standard, an extension of the production tax credit, and the 

adoption of a cap and trade program. All of these continue to be debated by Congress, and a cap 

and trade program is believed to be most cost-effective (Palmer and Burtraw, 2005). We also 

discuss the creation of national offshore-wind capacity goals, something that is common in 

Europe. There are other state-level methods of alternative energy promotion, but these are 

thought to be less effective (Birgisson and Petersen, 2006; Menz and Vachon, 2006). We do not 

intend this discussion to offer support or condemnation of these policies, only to discuss their 

likely impacts on offshore wind development. 

 

7.6.1. The Production Tax Credit

 

The PTC is similar to the tax credits in some European countries and is similar to a feed-in tariff 

(Toke, 2007). However, in European nations, the tax credits are generally exemptions from 

carbon taxes, which do not exist in the U.S. Among the most likely ways for the federal 

government to stimulate offshore wind energy would be through an extension or expansion of 

the PTC. The PTC is a reasonable stimulant for the onshore wind industry, but due to the long 

planning needed for offshore wind projects it is a poor stimulant for offshore wind energy (Wiser 

et al., 2007). 
72

The PTC has expired 3 times in the past decade and extensions of the PTC have been for only 

one or two years at a time. Most recently, the PTC was extended by the Senate until January, 

2010. However, this short extension is not long enough to allow for the long-term planning 

required by offshore wind farms. A project in the planning stages in 2008 would not be 

operational until well after 2010, when the PTC would again expire. In order to be useful for 

offshore wind farms, a PTC commitment of at least a decade is needed. 

 

Additionally, unlike tax credits in Europe, the PTC is designed to apply only for the first ten 

years of operation. However, the cost of energy is unlikely to decline for already established 

offshore wind projects over time. Thus, a company may be able to profitably produce electricity 

for the first 10 years of operation, but be unable to cover its operating expenses after it is no 

longer covered by the PTC. 

 

Critics of the PTC argue that it was originally designed to provide an incentive to the developing 

renewable energy industry and it should now be allowed to expire (Vann, 2007). However, 

unlike European feed-in policies, the PTC treats all renewable energy technologies equally. 

Thus, while onshore wind is now profitable and likely does not need the PTC in order to compete 

with coal and natural gas fired power, offshore wind power is a newly developing industry and 

cannot compete on price with conventional electricity. Thus, the PTC could reasonably be 

extended for 10 years for new offshore wind projects without defying its original purpose. 

In addition to extending the PTC, Congress could increase it. Again this could be done either for 

alternative energy in general, or some subset of technologies. In the case of offshore wind 

energy, the cost of production varies dramatically depending on site specific factors, but it is 

likely to average about 10 to 12 cents per kWh in the U.S. (Fingersh et al., 2006; Dept. for 

BERR, 2004; Mense, 2007). The wholesale price of electricity in 2007 at the NEPOOL hub in 

New England was 7.7 cents per kWh. This is the hub most likely to be impacted by offshore 

wind energy. If the PTC is meant to be a subsidy to encourage renewable energy development 

and to make it at least temporarily competitive with conventional electricity, then the PTC might 

need to be set to approximately 3 ¢/kWh in order to make it competitive with more traditional 

power sources. 

 

Each 1,000 MW of offshore wind capacity would cost the government 61 million dollars per 

year (with a 2 ¢/kWh PTC, $92 million with a 3 ¢/kWh PTC; assuming 35 percent capacity 

factor). If Congress were to extend the PTC for offshore wind for 10 years, it seems probable 

that no more than 2,500 to 5,000 MW of capacity could be built. This would suggest a 

maximum subsidy by the federal government of $152 to $305 million per year with a 2 ¢/kWh 

PTC. 

 

7.6.2. Greenhouse Gas Legislation 

The Lieberman-Warner bill was voted out of committee for consideration by the full Senate in 

December 2007 but failed to pass the Senate in June of 2008. It called for the establishment of a 

cap and trade program which would cap greenhouse gas emissions but would allow emitters to 

purchase offsets to satisfy up to 15 percent of their obligation. It would establish a national 

mandatory carbon market which would replace or supplement the voluntary market already in 
73

place. In the REC market the price of credits in compliance markets is often higher than the 

price of credits in the voluntary market.20 It seems likely that the imposition of a cap and trade 

program would therefore boost the price of carbon credits which would increase the costs of 

conventional electricity and increase the profitability of any renewable energy project. The 

Lieberman-Warner bill failed to pass in the 110th Congress. 

 

Carbon taxes have also been suggested as a means for combating climate change and are used in 

Europe. In the 110th Congress, two bills were introduced into the House of Representatives that 

proposed carbon taxes of $2.7 or $15 per metric tone of CO2 with incremental increases. A 

carbon tax would function to make non-renewable energy more expensive, thereby giving 

offshore wind power a competitive advantage. In the U.S. on average, there is 0.839 metric 

tones of CO2 emitted per MWh (Sims et al., 2003). Thus, a $10 per metric tone CO2 tax would, 

on average, increase electricity prices by 0.839 ¢/kWh. This is not enough to have an 

appreciable effect on the profitability of offshore wind power. Carbon taxes also do not seem to 

be as popular with lawmakers as are cap-and-trade programs. 

 

7.6.3. Renewable Portfolio Standards 

Twenty-five states and the District of Columbia have RPSs (DSIRE, 2008). This includes almost 

all of the states in which offshore wind is a realistic possibility (excepting Louisiana and 

Georgia). The U.S. Congress has considered the establishment of a national RPS (Nogee et al., 

2007). In 2007 the House and Senate debated bills that would set an RPS target of 15 percent 

renewable energy by 2020. The Senate has passed similar bills three times. The most recent 

bills also contained annually increasing goals between 2010 and 2020 and included trading 

schemes, penalties and caps for the prices of RECs. Opponents of the federal RPS argued that 

the system would be unfair to the South and Midwest regions of the U.S. because of the unequal 

distribution of renewable energy potential and that it would cost consumers billions of dollars. 

 

The combination of the federal PTC and state RPS has stimulated wind energy development 

(USDOE, EIA, 2006) with modest impacts on electricity prices.21 It is reasonable to expect that 

a federal RPS would similarly stimulate the offshore wind industry (Short et al., 2004). 

However, there are also reasons to doubt the efficacy of a federal RPS program for offshore 

wind. While federal legislation will only set a minimum RPS which states may exceed, most of 

the coastal states already exceed the proposed federal RPS. Thus, the only way that a federal 

RPS would be beneficial for offshore wind would be if it caused the prices of all RECs to 

increase. This may occur since a federal RPS would increase demand for RECs. 

 

Interestingly, if, following the passage of a federal RPS, a state allowed an electricity producer to 

purchase RECs to meet the federal RPS from outside the state, this might actually lower the price 

of RECs. For example, utilities in Massachusetts are required to supply 15 percent of their 

electricity from renewable sources by 2020, but they currently must purchase expensive 

Massachusetts RECs to offset gaps in production. If federal legislation passed, Massachusetts 

 

20 Similarly, as of March 2008 the price of carbon credits on the European Climate Exchange (a mandatory EU 

market) was seven times higher than the price of credits on the Chicago Climate Exchange (a voluntary market; see 

www.chicagoclimatex.com and www.europeanclimateexchange.com). 21 Increase in prices may be less than 1 percent (Chen et al., 2009; Wiser et al., 2007). 
74

electricity retailers could purchase RECs on a national market. While this new national market 

would have stronger demand than a regional market, its supply would also be much different. In 

a state market like that in Massachusetts, the production costs of RECs can be quite high because 

of limited renewable energy potentials. On a national market, RECs are likely to be dominated 

by onshore wind production which is already profitable without RECs and the supply of which 

would vastly outweigh RECs from offshore wind power. As a result, this could depress the price 

of RECs in many markets. 

 

7.6.4. National Goals for Offshore Wind Power 

Governments in Europe have frequently used national goals as instruments of policy. For 

example, Denmark set a goal of producing 15 percent of its energy from wind power by 2005. It 

has been argued that the establishment of this goal sent a signal to the wind industry that the 

national government was serious about the future of wind power and Denmark met this goal 3 

years early (Peloso, 2006). Similarly, the Dutch have set a goal of 6,000 MW of offshore 

capacity by 2020 (Mast et al., 2007). Goals can be purely aspirational, or they could be 

mandatory, as in state RPS standards. A national goal for offshore wind power in the U.S. could 

occur in the context of a larger goal for wind power or ocean energy in general. 

 

In May 2008, the U.S. Department of Energy released a report entitled “20 % Wind Energy by 

2030.” The report does not specifically advocate for generating 20 percent of U.S. electricity 

consumption with wind power by 2030, instead it is meant to discuss the feasibility of such a 

goal. The report concludes that this goal is ambitious but feasible and that it would have 

numerous benefits. The DOE report assumes that offshore wind power capacity is about 50 GW 

in 2030, about 15 percent of overall 2030 wind capacity. 

 

A relatively modest but achievable goal might be to have 5 GW of capacity (roughly 10 to 12 

Cape Wind sized developments) by 2020. Total nameplate U.S. electrical capacity in 2006 was 

1,075 GW, so this commitment would only account for one-half of one percent of capacity. The 

goal described in the 2008 DOE report of 50 GW by 2030 would require at least 100 Cape Wind 

sized projects. Given the limited shallow-water offshore wind resources of the U.S., this goal 

would be difficult to achieve without deep-water technology. 

 

The effects of a goal would differ markedly depending on if the goal were part of a national 

technology specific RPS program (and thus a mandate) or an aspirational goal. Several states 

specify the proportions of certain technologies that must be used to meet RPS standards. The 

federal government could follow this example; however, this seems unlikely. A voluntary goal 

would not change the underlying economics of offshore wind and it therefore seems unlikely that 

it would have significant impacts on the development of the industry. 

7.7. Conclusions 

The development of the offshore wind industry in Europe has been largely driven by government 

policies and financial incentives. The types and scale of financial incentives used in Europe 

seem unlikely in the U.S. since the U.S. has no international obligation to limit carbon emissions 

and generally seems to prefer “market-driven” solutions like cap-and-trade or renewable energy 
75

credit programs over either carbon taxes or feed-in prices. This, combined with the fact that 

Northern Europe has several sites that are well suited for offshore wind with currently available 

technology, makes it unsurprising that the offshore wind industry has developed outside the U.S. 

It is important to note that the U.S. does have sites that are amenable to offshore wind energy, 

but that if policymakers hope to see offshore wind development in the U.S. commensurate with 

that of Europe, they will have to increase subsidies. 

 

From the perspective of offshore wind development, the most useful policy change would be a 

modest increase in the size and duration of the PTC. A 10 year commitment is necessary in 

order for new offshore developments to be able to have confidence that it will be available. 

While the lack of regulation has stalled development in the past, this problem is being corrected, 

and it seems unlikely that the leasing system and fees under development by the BOEMRE will 

forestall development in the future. 

 

The ambitious plans of small start-up companies might concern some stakeholders interested in 

the development of a viable offshore wind industry since they are quite different from the 

development of the European industry. It is not clear that all of the developers interested in 

offshore wind in the U.S. have the requisite infrastructure and institutional capacity to develop a 

new commercial offshore industry. However, if these companies can finance their projects and 

use the marine construction experience of the offshore oil and gas industry or other marine 

construction industries, then they may be able to rapidly develop a commercial offshore wind 

industry and skip over the long slow period of experimental development that occurred in 

Europe. 

Onshore wind development is experiencing rapid growth in the U.S. and is the second largest 

source of new capacity additions behind natural gas (Wiser and Bolinger, 2008). If this growth 

continues, at some point onshore resources will no longer be readily available, increasing the 

costs of onshore wind due to the costs of leasing land, and making offshore wind more attractive. 

In 2007, over 5,000 MW of new capacity was added. Assuming a turbine density of 5 MW per 

km2

, then over 1,000 km2 were converted to wind farms in 2007 (USDOE, 2008a). Presumably, 

the sites with the highest wind speeds and lowest land lease or purchase costs are developed first. 

When these sites are no longer readily available, offshore development may expand. 

Even if the first offshore wind developments in the U.S. are successful and the profitability of 

offshore wind farms in the U.S. is increased through increased government subsidies, the 

different wind conditions and population densities in Europe and the U.S. will ensure that 

offshore wind is more common in Europe than the U.S. The fact that onshore wind resource 

sites are still widely available in the U.S. and that the onshore environment is inherently less 

costly and risky will cause offshore wind to be at best a small contributor to electricity 

production in the U.S. for the foreseeable future. 

 
77

8. ECOLOGICAL AND ECONOMIC COST-BENEFIT ANALYSIS OF OFFSHORE 

WIND ENERGY

In this chapter, we seek to address the question, “Is investment in offshore wind power preferred 

over investments in fossil fueled or onshore wind power.” We focus primarily on coal fired 

power as representative of fossil fueled power since it is the dominant source of electricity in the 

U.S. and it is both inexpensive and a major source of greenhouse gases. 

We begin with an overview of the commonly expressed criticisms and benefits of offshore wind 

power. We discuss cost models for offshore wind power and compare to onshore wind power 

and conventional power. We also discuss the factors that lead to higher costs through a firstorder empirical cost function and discuss how costs can be reduced. We discuss the 

environmental impacts of offshore wind power and how these factors can be mitigated. We end 

the chapter with the conclusions of the analysis. 

8.1. Introduction 

Over the past 10 years, the onshore wind industry in the U.S. has grown dramatically and as a 

result developers, citizens and the U.S. Congress have expressed interest in the development of 

an offshore wind industry. Several companies have developed plans for offshore wind projects 

and the BOEMRE is in the process of reviewing these applications and developing regulations 

for the industry while the state of Texas has already leased lands for at least one and possibly 

several additional offshore wind farms. Lawmakers, government agencies, corporations, nongovernmental organizations and private individuals are deciding whether or not to support or 

participate in the development of an offshore wind industry, and the relative level of support or 

encouragement to give. In making these decisions, stakeholders will have to balance the 

ecological costs and benefits of offshore wind against its economic costs and compare to 

offshore wind energy’s most realistic competitors. The decision is complex and requires 

balancing local and global environmental issues, historical conservation and economic costs. 

Given the uncertainties associated with global climate change, it is difficult to compare the 

societal costs and benefits of wind energy to fossil fueled energy. However, one way to develop 

a first order comparison of these costs would be to include the costs of market based carbon 

offsets in the costs of conventional electricity. This assumes that the costs of carbon emission 

credits accurately reflect their ecological value which would occur if carbon credits actually 

represent a reduction of the specified amount of carbon dioxide from the atmosphere. 

8.2. Criticisms of Offshore Wind Power

There have been a number of criticisms of offshore wind power in the U.S., mostly associated 

with the Cape Wind project (Table H.1) (Firestone and Kempton, 2007; Firestone et al., 2007). 

The environmental impacts are discussed in more detail below, the rest of the concerns are 

discussed here. 
78

8.2.1. Navigational Safety 

Any structure placed in federal water must receive a permit from the Army Corps of Engineers 

(COE). The COE, through the Rivers and Harbors Act (RHA), has the authority to regulate 

obstructions to navigation in federal waters. The COE considers a multitude of factors in making 

RHA decisions; however, their primary responsibility is protecting navigation. Therefore, they 

are unlikely to permit offshore wind projects that pose serious threat to U.S. shipping lanes. 

However, densely spaced wind turbines could provide a problem for recreational boats and small 

fishing vessels attempting to navigate through a wind farm, and for commercial vessels passing 

nearby. The amount of acreage covered in wind farms for a 400-600 MW site will likely range 

between 25-40 square miles. Typically, turbines in a wind farm are spaced 500 to 1,000 m apart 

and have blades that at their lowest point are at least 20m above the water. Small boats should 

therefore have no problem navigating among these turbines in good weather; however, critics of 

the Cape Wind project, including the Alliance to Protect Nantucket Sound, have pointed out that 

the coast of Massachusetts is infamous for bad weather and shipwrecks. This is likely to be the 

case in many places in which offshore turbines are particularly profitable (i.e. areas with high 

winds). 

8.2.2. Federal Subsidies 

Opponents of offshore wind projects claim that offshore wind power is not economically viable 

without federal “subsidies”, by which they mean federal tax credits for renewable energy. The 

federal Production Tax Credit (PTC) gives a tax credit of 2 cents per kWh of produced electricity 

for the first ten years of production from any renewable source, including wind.22 Opponents of 

the PTC argue that its original purpose was to help the renewable energy industry become 

established and because it originally became law in 1992, it should now be allowed to expire. In 

fact, the PTC did expire in 2000, 2002 and 2004 and is currently set to expire at the end of 2008. 

Interestingly, the pattern of wind capacity growth in the U.S. seems to closely follow the 

expiration of the PTC (Bird et al., 2005). In each of the years in which the PTC was allowed to 

expire, the growth in wind capacity slowed markedly. Given the relatively unfavorable 

economics of offshore wind, it is reasonable to suggest that offshore wind energy projects will 

need the continuation of the Production Tax Credit (PTC) in order to be competitive. 

8.2.3. Aesthetics 

Opponents to wind power claim that wind turbines mar the landscape or seascape. This is 

especially an issue for the Cape Wind project in which local activists are concerned about the 

views from historic landmarks. There are some aesthetic issues that are beyond the scope of 

analytic tools, however, the effects of wind farms on property values has been analyzed. 

Sterzinger et al. (2003) analyzed property values in the viewshed of onshore wind turbines and 

found that in eight out of ten cases the property values in the viewshed increased faster than the 

values in control sites. Furthermore, in nine of ten cases the rate of property value increase rose 

 

22 For example, if a 400 MW wind farm has a capacity factor of 50 percent, then it would produce about 1.7 billion 

kWh of electricity annually, and would qualify for 35 million dollars in tax credits each year for the first ten years of 

its operational life. 
79

after the placement of the wind farm. Thus, there is no empirical evidence to suggest that wind 

farms negatively influence property values. 

In Denmark, Ladenburg and Dubgaard (2007) estimated the willingness of citizens to pay for 

moving turbines further from shore. They found that respondents were willing to pay 46, 96 and 

122 Euros per year per household in order to move a theoretical wind farm to 12, 18 or 50 km 

away from the coast, relative to a 8 km baseline (Ladenburg and Dubgaard, 2007). Haughton et 

al., (2003) conducted a similar study on Cape Cod and found that 22 percent of respondents were 

willing to pay, on average, a one time cost of $286 dollars for windmills to not be built, while 9 

percent were willing to pay an average of $112 for windmills to be built. The average net 

willingness to pay per person was $75. These data suggest that on average the public views 

offshore wind turbines as visual disamentities, at least before they are built. 

8.2.4. Cost and Risk 

The offshore environment is significantly more uncertain and difficult than onshore, and thus, 

more costly and risky. The offshore environment involves personnel traveling to and from 

offshore turbines; this increases costs as well as insurance due to increased risks. Offshore work 

involves increased risks of storms which affect the amount of time available for maintenance and 

installation which in turn influence capital and operation costs. Offshore environments are 

corrosive to electrical and structural equipment and require turbines to be marinized with 

cathodic and humidity protection. Capital expenditures for offshore wind projects depend on 

marine vessel dayrates which are unpredictable, and offshore foundations require more steel for 

jackets and pilings than onshore foundations. 

8.2.5. Unpredictable Power 

One of the most substantive criticisms of wind power is that it is unable to provide constant, 

predictable power to the grid. The electricity grid is designed to send a constant AC load to 

consumers and it relies on large power plants producing predictable and steady electricity. Wind 

energy is not steady and varies on the scale of minutes, hours, days and months and the changes 

in wind power output are difficult to predict ahead of time (Hirst and Hild, 2004). Therefore, 

integrating wind power into the electricity grid will require backup systems (especially natural 

gas fired power plants) that can respond quickly to changing production from wind farms (Lund, 

2005). This increases the total national cost of electricity. The DOE has estimated that the cost 

to supply up to 20 percent of the nation’s electrical use from wind power would cost up to $5 per 

MWh in integration costs (USDOE, 2008a). 

8.3. Benefits of Offshore Wind Power 

Offshore wind power shares all of the same benefits of onshore wind power relative to 

conventional power sources (Table H.1). Most notably, wind power has very low carbon 

emissions over its lifecycle, as well as negligible emissions of mercury, nitrous oxides and sulfur 

oxides. Wind power does not use fuel and is therefore freed from the price volatility associated 

with electricity generated from oil, natural gas, biomass, nuclear and coal. Wind power does not 

rely on large sources of freshwater as conventional sources of power do (USDOE, 2008a). In the 
80

near term, offshore wind power will be more expensive than onshore wind power; however, 

there are several benefits of offshore wind power that are not shared by onshore wind; these 

benefits may or may not justify the additional costs. 

8.3.1. Location 

Onshore wind resources in the U.S. are localized in the middle of the country, far away from 

large population centers. Offshore wind power is physically close to the major population 

centers of the coastal United States, thereby removing the need for expensive high voltage 

transmission (USDOE, NREL, 2008). However, with a large enough investment, it may be more 

efficient to build these transmission lines than it would be to invest in offshore wind power. 

Recent studies have evaluated the costs of producing 20 percent of the nation’s electricity from 

wind (primarily onshore wind). The cost to transmit this electricity from the wind centers of the 

west and Midwest to the population centers on the coasts has been estimated to be about $20 to 

$26 billion. This would add about $120 to $180 to the capital costs of new construction making 

total capital costs about $2000/kWh, below current offshore costs of around 3000 to 4000 $/kWh 

(USDOE, 2008a). 

Onshore wind power has, in some cases, been stalled by local opposition due to conflicts 

between alternative land uses (Righter, 2002). One potential benefit of offshore wind is that it 

may reduce this conflict (Pasqualetti, 2004). Wind turbines can be placed far enough from the 

shore to be inaudible and, potentially, invisible. Local opposition to the Cape Wind project 

remains strong, but does not seem to be the case in the Galveston Offshore Wind Project 

(Patterson, 2005). 

8.3.2. Power 

Offshore winds are generally stronger and more constant than onshore winds. As a result, 

turbines are expected to operate at their maximum capacity for a larger percentage of the time, 

and the constancy of wind speed reduces wear on the turbine and provides a more constant 

source of power to the electrical grid reducing the need for other sources of electricity to serve as 

backups (IEA, 2005a). The increase in wind speed has been reported to lead to a 150 percent 

increase in electricity production for offshore wind turbines (Vattenfall, 2008) and an increase in 

the capacity factor of the wind farm from about 25 to 40 percent (Junginger et al., 2004). 

8.3.3. Transport and Construction 

 

The marine cranes developed for the offshore oil and natural gas industry are capable of handling 

larger equipment than onshore cranes, thus allowing for larger turbines to be efficiently erected 

at sea. The transportation of the required enormous pieces of equipment is also made 

significantly easier at sea (Musial and Butterfield, 2004). The size of onshore turbines is limited 

by the ability to transport the blades, tower and nacelles (the section of the turbine to which the 

blades are attached and that houses the mechanical and electrical equipment) of the turbines. As 

a result, cost reductions due to the economics of scale are limited. However, at sea these 

constraints are not an issue and wind turbines already exceed 5 MW and will likely eventually 
81

exceed 10 MW. These larger turbines may make offshore wind power more economically 

attractive due to the economies of scale. 

8.3.4. Design Considerations 

Offshore wind power also has several potential benefits that have not yet been realized due to its 

nascent nature; these benefits are related to the potential for new turbine designs optimized for 

the offshore environment (Lemming et al., 2007). 

Turbine noise is an oft-cited criticism made by opponents to onshore wind power (Pedersen and 

Waye, 2004). The offshore wind power industry does not have to be as concerned about turbine 

noise as does the onshore industry. As a result, the offshore industry can use far larger turbines 

(Musial and Butterfield, 2004). These larger turbines should make offshore wind power more 

economically attractive due to scale economies. Additionally, if offshore turbines are freed from 

constraints of noise, then turbine manufacturers could build turbines with downwind rotors, that 

is, rotors that are located behind (with respect to the wind direction) the support tower and 

nacelle. In upwind rotors, extreme wind speeds could deflect the blades back towards the tower. 

Thus the blades have to be made very stiff, increasing their price and weight (the increased 

weight also increases the expense of the tower, foundation and construction). In a downwind 

rotor the blade can be more flexible. However, as the blades pass through the wind shadow 

caused by the tower they create a low frequency noise. Offshore wind farms would not need to 

be as concerned with this noise (Butterfield et al., 2007). 

Offshore wind farms located over the horizon could also make use of lattice towers instead of 

tubular towers. These lattice towers require less material and are therefore lighter and cheaper 

than the more common tubular towers; however, they are rare for aesthetic reasons (Gipe, 2004). 

Similarly, two bladed turbines were rejected by the European market for aesthetic reasons 

(Butterfield et al., 2007); however they are lighter (and therefore less expensive) than three 

bladed turbines. 

8.4. Cost Estimates of Wind Power 

The economic costs of conventional, onshore and offshore wind power are shown in Table H.2. 

The estimate for conventional power comes from an average of all power generation in the U.S. 

There is a great deal of variation in the estimates for offshore wind costs which is due to the 

assumptions of the analysts and the year in which the estimates were performed. Commodity 

prices have increased significantly in recent years, and the costs of turbine construction and 

installation have also increased, both onshore and offshore. Additionally, the methodology 

through which cost estimates are made, and their potential application can differ significantly. 

What is clear is that the costs of onshore wind power are competitive with conventional power 

sources, but that the costs of offshore wind power are more expensive than either onshore or 

conventional electricity perhaps by a factor of 2 to 3. The exact price of the premium is time and 

site specific, but may be up to $50/MWh. Since onshore wind is cost competitive with 

conventional electricity, the premium is similar for both energy sources and may be higher for 

onshore wind than for conventional power. 
82

8.4.1. Costs of Onshore Wind Power 

Data on the costs of offshore wind power is relatively sparse due to the limited number of 

installations and the lack of reporting. Data on onshore wind power costs are more readily 

available. The price of onshore wind generated electricity (cost of energy; CE) declined from 

1999 to 2005 from approximately $63/MWh in 1999 to $36/MWh in 2005 (Wiser and Bolinger, 

2008). However, in 2006 the price began to rise again and in 2007 the price of wind generated 

electricity was $40 per MWh (all prices in 2007 dollars). Even with this increasing price, wind 

power is competitive with conventional power sources; since 2003 wind generated electricity has 

been at or below the average national wholesale price of power. 

 

Part of this rising price is attributed to the rising capital costs of wind farms. From the early 

1980’s to the early 2000s, capital costs of wind farms declined by $2,700/kW (Wiser and 

Bolinger, 2008). From 2001 to 2003 the capital costs for onshore wind farms averaged about 

$1,450/kW; by 2007 these costs had risen to $1,710/kW. These increasing project costs are due 

to increasing turbine costs which have increased as demand and commodity prices have grown. 

The primary drivers of the CE are the capital costs of a wind farm and the capacity factor. CE 

increases with the capital costs and decreases with the capacity factor (Wiser and Bolinger, 

2008). 

8.4.2. Offshore Cost Estimates 

Musial and Butterfield (2004) developed a model of the costs of offshore wind farms. They 

modeled a hypothetical 500 MW wind farm composed of 100, 5 MW turbines. The farm was in 

shallow water, 15 miles from the coast. They assumed that the turbines would cost $340 million, 

the foundations $100 million and the electrical connections $160 million. This gave a total 

construction cost of $1,200/kW and a cost of energy of $54/MWh. 

Fingersh et al. (2006) modeled the costs of a single 3 MW turbine in shallow water, but included 

the per turbine costs of electrical interconnection. The cost of electricity was a function of the 

annual expenses divided by the annual energy production. The annual expenses included the rate 

of return on the initial capital investment (11.85 percent) times the initial capital required ($6.3 

million; $2,100 per kW) plus the land lease costs ($12,000), operation and maintenance costs 

($215,000 per year), and replacement and overhaul costs ($55,000 per year). Fingersh et al. 

(2006) assumed a capacity of 38 percent and predicted the total costs to be $95/MWh. They 

used a similar method to estimate the costs of onshore wind power and found them to be roughly 

half the costs of offshore wind power. 

In the now defunct Long Island Offshore Wind Park (LIOWP) agreement between FPL Energy 

and the Long Island Power Authority (LIPA), LIPA agreed to pay $94.97/MWh for offshore 

produced wind power. This rate was designed to increase annually at 2.75 percent (Greer, 2007). 

PACE Global Energy Services conducted an independent report for LIPA and found that the 

costs of construction were approximately $750 million ($5231/kW). This translated into a cost 

of energy of $291/MWh (PACE, 2007). PACE also estimated the costs of a future (2010) 
83

generic European offshore wind farm at $4,000/kW. This high cost is due to the increasing price 

of materials (PACE, 2007). 

8.4.3. Cost Components 

The primary component costs for on and offshore wind based on empirical studies are shown in 

Figure H.1. The primary capital cost for onshore wind projects is the turbine; installation costs 

make up about 14 percent of the total capital costs. For offshore wind projects, the costs of 

installation is higher, approximately 20 percent of the total costs and the costs of building and 

installing the foundations account for another 20 percent of capital costs. For offshore wind, 

operation and maintenance costs make up a larger proportion of the overall components of the 

CE (Fingersh et al., 2006). This is likely due to the costs of accessing offshore wind farms and 

maintaining turbines in operating condition. 

8.5. Offshore Cost Functions 

8.5.1. Data Source 

We have compiled data from a variety of public sources on the costs of offshore wind farms built 

in Europe (Table H.3). Construction costs have ranged in price from $1,462 to $7,000 per kW of 

capacity and average $3,354 per kW of capacity. Excluding Beatrice, estimated costs for not yet 

completed wind farms and developments built before 2000, construction costs for wind farms 

built between 2001 and 2007 ranged from $1,462 to $3,125 per kW. We believe the smaller 

sample is more representative of general trends and use it in further analyses. 

These data come from a variety of sources including developer websites which we cannot 

independently verify. These data may not reflect the entire costs of construction in all cases such 

as the cost of transmission studies and permitting. The cost data were inflated to 2008 dollars by 

converting the original cost to dollars using the average exchange rate in the year in which the 

estimate was given (assumed to be the year of construction unless otherwise indicated), then 

inflating to 2008 dollars using the U.S. Bureau of Labor Statistics calculator. 

8.5.2. Model Specification 

We created multiple regression models of capital cost based on several factors. We hypothesized 

a cost model in which the predictor variables were total capacity, water depth, distance to shore, 

year constructed, turbine size, and number of turbines. We had no reason to assume that any 

interaction or higher-order terms would be appropriate, and the cost models should be viewed as 

a first-order approximation in a complex environment. 

Total Capacity

Obviously, increasing the size of development will increase the capital costs of a project and this 

parameter is needed in order to control for varying sizes of developments. However, the costs 

are unlikely to scale linearly with the size of development. Installation costs, and grid 

connection costs, and even turbine costs are unlikely to scale linearly with the size of the wind 
84

farm. For example, for orders of over 100 turbines manufacturers typically provide for a 20-30 

percent reduction in the list price (Junginger et al., 2005). Nonetheless, we expect that the total 

capital costs will increase with increases in total capacity. 

Turbine Capacity

There is a clear trend toward increasing turbine size in onshore (Wiser and Bolinger, 2008) and 

offshore applications. This could decrease costs since larger capacity turbines would require 

fewer foundations for the same sized wind farm. However, larger components require larger 

barges and cranes for construction which are less common and more expensive than smaller 

barges. There is no relationship between turbine capacity and the per kWh capital costs of 

offshore wind farms (Figure H.2) and so we do not hypothesize a relationship between 

increasing turbine capacity and capital costs. 

Distance to Shore

The distance to shore influences both the construction and operation and maintenance costs. 

During construction the ships will have to make a number of trips between the site and shore to 

load equipment. This travel period is costly and therefore the closer a offshore site is to an 

industrial port facility, the less expensive installation will be. Furthermore, the distance to shore 

also dictates the amount of transmission cabling required. During operation a maintenance crew 

will need to make regular trips to the wind farm to monitor the foundations, towers and turbines 

(Larsen et al., 2005). Locating this crew as close as possible to the wind farm will decrease both 

the environmental impacts and the costs of maintenance. We expect distance to shore to be 

positively related to capital costs. 

Water Depth

Water depth is a primary factor in most offshore operations in the oil and gas industry, and thus 

we suspect water depth will also play an important role in determining costs in offshore wind 

development. Increasing depths increase the price of construction by making monopile and 

gravity foundations impractical and potentially requiring the use of expensive, jacketed 

foundations and expensive marine vessels for installation (Butterfield et al., 2007). Shallow 

water can restrict the access of some large barges which could also restrict operations. Many 

cable laying vessels have deep drafts (up to 8 m); therefore shallow water may necessitate the 

use of remotely operated vehicles (ROVs) for cable laying operations. Use of ROVs and divers 

in offshore construction will significantly impact costs. 

Year of Construction

There is a general expectation that technological learning will cause the cost of offshore wind 

installations to decrease (Junginger et al., 2004). This has occurred in the onshore wind industry 

with consequent expansion in capacity, and there is a great deal of expectation that a similar 

phenomenon will occur in the offshore wind industry. Year of construction may be negatively 

associated with capital costs, but we do not suspect the sample set is sufficiently large to detect 

such effects. 
85

8.5.3. Model Results 

We checked the variables for colinearity using a correlation matrix and found no parameters with 

correlation coefficients greater than 0.7. Therefore, we left all parameters in the model and 

applied various combinations of the parameters and ranked the models according to their 

adjusted R2 value. The models and their parameter estimates are given in Table H.4. While the 

adjusted R-squared of model one is the highest (indicating it explains the most variance) model 2 

may be the most parsimonious model. 

Three variables common to all three of the best models were total capacity, distance to shore, and 

turbine size. As expected, costs increased with increases in total capacity and distance to shore, 

and decreased with increases in turbine size. This suggests that as turbines increase in size the 

total costs of offshore wind power will decline. The year of construction and water depth were 

not significant in any of the models. The water depths in the sample set ranged from 1 to 21 

meters which is not sufficient to detect depth effects. The cost element is also too gross to 

expect time to play a significant role in the model. 

8.5.4. Limitations of Analysis 

 

The capital costs of offshore wind farms is governed by conditions unique to the structure, site, 

contractor, and country as well as the prevailing environmental, engineering, market, operational, 

and regulatory conditions at the time of the operation. The unique nature of offshore operations 

and construction objectives drives the variability observed and can only be partially explained 

through factor analysis. 

8.6. Managing Costs 

With a CE of up to $100 per MWh, offshore wind is not currently cost competitive with either 

onshore wind or conventional electricity. However there are a number of factors which may lead 

to significant cost reductions in the future and there are many factors that may make offshore 

wind locally attractive. The CE for offshore wind power is determined by the capital costs of 

installation, the interest rate, the operation and maintenance costs, the energy produced, and the 

sales price of electricity. These factors are in turn determined by a variety of other factors. 

Offshore wind developers have little control over some of these factors (e.g., the interest rate), 

but site selection and project planning can reduce costs and increase revenues. Furthermore, the 

costs of offshore wind may decrease over time due to technological learning. 

 

8.6.1. Factors Influencing Revenue 

The wind profile at a site determines the cost of energy and the revenue to a wind farm operator 

by determining the number of kWh sold. Since wind power scales with the cube of wind 

velocity, the velocity of the air is likely to be the most important single factor in determining the 

placement of offshore wind farms and their profitability. The strongest winds offshore of the 

U.S. occur in the Aleutian Islands in Alaska, off the coast of northern California and southern 

Oregon, and in the Atlantic Ocean off the southern and eastern coasts of Massachusetts. In all of 

these places wind speeds at 50 m average 8.8-11.1 m/s (USDOE, NREL, 2008). While these are 
86

the largest concentrations of strong winds, there may also be areas of class 7 winds at 80 m off 

the coasts of Texas, Louisiana, North Carolina and Long Island (Archer and Jacobson, 2005); 

however, these winds were not identified by some other studies (USDOE, NREL, 2008). 

The CE is also determined by the time of the day in which these winds blow. Electricity is not 

equally valuable throughout the day and developers interested in site selection need to know not 

just the mean annual wind speed, but the time of day and time of year in which the wind is 

strongest. 

Revenue is determined by costs of energy at the local level. In the U.S. the average retail price 

of electricity ranges from 4.92 to 20.72 ¢/kWh (USDOE, EIA, 2008). Thus an offshore wind 

farm may not be practical in Washington (average retail price of electricity is 6.14 ¢/kWh) but 

may be very profitable in Hawaii where the average price is over three times higher (20.72 

¢/kWh). 

Revenue is also impacted by what other marketable products the wind farm generates. In states 

with Renewable Portfolio Standards (RPS), wind farm operators could sell renewable energy 

credits (RECs). States with RPS include most of the states with offshore wind potential with the 

exception of Ohio, Georgia, Louisiana and Michigan. The prices of RECs vary dramatically 

with the most expensive RECs being about 45 to 55 $/MWh in Massachusetts, Connecticut and 

Rhode Island. 

The differences in local prices for electricity and RECs mean that the Cape Wind project may be 

able to sell its electricity for about 13 ¢/kWh (average wholesale price of electricity in New 

England in 2007 was 7.7 ¢/kWh; average REC price is 5.5 ¢/kWh), while the Galveston Offshore 

Wind project may only be able to sell electricity at half that rate (average wholesale price of 

electricity in Texas in 2007 was 5.7 ¢/kWh; average REC price is 0.5 ¢/kWh) (Wiser and 

Bolinger, 2008; USDOE, EIA, 2008). These differences in revenue could determine if a wind 

farm would be competitive with fossil fueled fired electricity or not. 

8.6.2. Site Selection Impacts 

Previously, we discussed the possible impacts of water depth and distance to shore on capital 

costs; however, other factors associated with the site selection will also impact capital costs, for 

example, seafloor geology. Most offshore wind farms have been established using monopiles. 

However, monopiles are impractical in rocky soil since they may require drilling. Suction 

caissons have been employed as foundations for some turbines and they have been installed in 

both clay and sandy soils, but, firmer substrates require larger pressure difference between the 

outside and inside of the caisson. Therefore, suction foundations may be impractical in some 

shallow water applications. 

Areas with extreme weather events, and even areas with a high frequency of moderate weather 

events, can also influence costs. Moderate waves (above 2 m) can delay construction and affect 

the proportion of time that maintenance crews can access the turbines. 
87

Hurricanes could dramatically influence the costs of construction and insurance. Current 

onshore towers are built to withstand 120 mph winds; hurricanes often have winds that 

significantly exceed this threshold. WEST, a company interested in building an offshore wind 

farm off the coast of Texas, has developed plans for a wind turbine that could withstand winds in 

excess of 150 mph (Schellstede, 2008); it is unclear how much this might add to the cost of a 

turbine. Given the frequency of hurricanes in the Gulf of Mexico and the 20 to 30 year lifetime 

of a wind farm, it seems prudent for any wind farm to plan on being impacted by one or more 

hurricanes over its lifetime. 

8.6.3. Project Specific Impacts 

 

The costs of installation are partly determined by how many of the components are assembled on 

land (Deepwater Wind, 2009). In some cases, developers have assembled components and even 

complete turbines on land and then shipped them to the installation site. This may decrease the 

time in which barges are needed but increase the sizes of the barges needed for construction. 

Barge costs are determined by the market; if wind farm development increases barge utilization 

then demand conditions will likely increase dayrates. Contracts with barges can be on either a 

turnkey or dayrate basis. Turnkey contracts transfer the operational risks associated with 

construction to the contractor; the party who holds weather related delay is determined by the 

terms of the contract. 

8.6.4. Economies of Scale 

The largest wind turbines in the world are built by two German companies, Enercon and 

Repower. Enercon is building a 6 MW prototype land based turbine while Repower sells a 5 

MW turbine. Plans for a 10 MW vertical offshore wind turbine have also been reported. 

Physical principles suggest that these larger machines should be more expensive per kW than 

smaller turbines because the material needed for a turbine should scale with the third power of 

rotor diameter while the power should scale with the square of rotor diameter (Butterfield et al., 

2007; Junginger et al., 2004). However, empirical data suggest that the cost per kW of capacity 

has stayed relatively constant with increasing rotor diameter due to technological innovation 

(Butterfield et al., 2007) and the weight of the blades and the nacelles has scaled with the 

exponents 2.3 and 1.5 respectively, rather than the cube as expected (Junginger et al., 2004). 

This, combined with the fact that operation and maintenance costs are lower for wind farms with 

fewer, larger turbines, means that as the scale of wind farms increases, the costs of energy may 

decrease (Grimley, 2007). These cost reductions reach a limit for land-based wind farms due to 

the high costs of transporting huge turbines and blades. For offshore turbines transportation over 

roadways is not an issue, and it is likely that the size of offshore turbines may continue to 

increase above 5 MW (USDOE, 2008a). We would expect that wind farms using large turbines 

would therefore be cheaper on a per kW capacity basis, but so far this has not occurred (Figure 

H.2). 

We might also expect larger wind farms to be less expensive on a per MW basis than smaller 

wind farms (Dept. for BERR, 2004). This could occur through discounts with large turbine 

purchases, through learning associated with installation of foundations, through operation and 

maintenance efficiencies or through decreasing per MW electrical connection costs. However, 
88

the data for onshore wind farms do not seem to support this expectation (Wiser and Bolinger, 

2008) nor do the data for offshore wind farms (Figure H.3). 

8.6.5. Technological Learning 

Musial and Butterfield (2004) predicted that the CE for an offshore wind farm in shallow water 

would decline from 54 $/MWh in 2006 to 32 $/MWh 2025 based on technological learning and 

independent of cost reductions through scale economies. 

There are several ways in which technological learning could take place; it could occur through 

incremental developments, the development of new main components, or through the 

development of entirely new turbine concepts (Lemming et al., 2007). Incremental development 

consists of developing new methods for turbine installation, advanced blade materials, easier 

access to the turbines, and more reliable electronic components, and is expected to be the major 

source of future price reductions23 (Lemming et al., 2007; ODE, 2007). Other options for 

technological cost reductions include the use of DC transmission, the mass production of 

jacketed structures, and the assembly of turbine components onshore (Junginger et al., 2004; 

Lemming et al., 2007; ODE, 2007). 

8.7. Environmental Impacts of Offshore Wind Power 

Offshore wind power has both positive and negative environmental consequences. The negative 

environmental consequences are generally local, whereas the positive environmental 

consequences are global and exist only insofar as offshore wind power displaces other forms of 

electricity generation. The environmental impacts studied in the Cape Wind EIS (USDOI, 

MMS, 2008a) are shown in Table H.5, but note that the U.S. Fish and Wildlife Service has 

objected that the data used to make the determinations in Table H.5 were not adequate (Bennett, 

2006). In general, the environmental impacts of offshore wind are similar to those from onshore 

wind; however, offshore wind has additional environmental impacts, primarily associated with 

the effects of noise on marine animals, that onshore wind does not share. 

8.7.1. Impacts on Birds 

One of the primary concerns surrounding wind farms is the risk that they will cause excessive 

avian mortality through collisions. The birds most at risk of collision will be seabirds, and in 

some cases migrating passerines. While bird mortality increases due to the risk of colliding with 

offshore turbines, the rate of mortality is relatively low, from 0.01 to 23 mortalities per turbine 

per year (these data are from both on and offshore wind farms; Drewitt and Langston, 2006). On 

a per MW basis, fatalities range from 0.95 to 11.67 deaths per year (Strickland and Johnson, 

2006). Altamont pass in California became notorious for its bird mortality. While the annual 

collision rate per turbine was low (0.02 to 0.15 collisions per year), mortality was still sizable 

due to the fact that 7000 turbines were involved and many of the birds killed were golden eagles, 

 

23 One example of this could be the learning that occurred during the Horns Rev installation. Eighty turbines were 

installed at Horns Rev. At the start of construction the average installation time was 3 days; by the end of the 

construction period an average of 1.4 turbines was installed per day (Junginger et al., 2004). 
89

a charismatic species (Drewitt and Langston, 2006). These data suggest that the fatality rate may 

be highly dependent on site specific factors. 

The estimates above were generally taken from studies in which mortality was measured by 

counting dead birds found near turbines and, in some cases, correcting for birds removed by 

scavengers. In the offshore environment counting carcasses is likely to be very difficult due to 

the fact that many carcasses will not be found (Bennett, 2006). At Nysted, a thermal imaging 

system was placed on one of the turbines and could monitor 30 percent of the swept area for bird 

collisions. Using these data, it was predicted that approximately 0.02 percent of birds would 

collide with turbines. 

Wind farms can also pose barriers to birds. Birds often seem to avoid flying through wind farms; 

this likely decreases their mortality (Desholm and Kahlert, 2005). However, birds that avoid a 

wind farm must expend a significant amount of energy flying around it, especially since offshore 

wind farms can be quite large (tens of square miles). This could be of particular importance if a 

wind farm is located in between rookeries and feeding grounds (Drewitt and Langston, 2006). 

Finally, wind farms can remove essential habitat from seabirds. Many seabirds have restricted 

areas in which they can successfully feed and in many cases these areas are shallow sand banks 

appropriate for wind farm development. If birds avoid wind farms, then even though the 

footprint of a wind turbine foundation is very small, very large areas of habitat may be 

inaccessible to birds. This seems to have occurred among diving birds at the Horns Rev wind 

park and long-tailed ducks at Nysted wind park. Similar patterns are seen for terns and auks at 

Horns Rev, although the trends are not significant (DONG Energy et al., 2006). 

8.7.2. Impacts on Marine Mammals 

Many cetaceans use echolocation to find food and many more communicate via acoustic signals. 

As a result many cetaceans, particularly porpoises, have very sensitive hearing which can be 

damaged by the loud noises associated with wind farms, particularly the sounds of pile driving. 

At the site of construction, the sound pressure level of pile driving a monopole for a 1.5MW 

turbine is 228 dB (Thomsen et al., 2006). Four-hundred meters away from pile driving the sound 

pressure level is 189 dB. This would cause hearing loss in seals. Hearing loss for porpoises 

would likely extend 1.8 km away from the source. Pile driving would be audible to porpoises 

and seals for at least 80 km and might cause behavioral responses up to 20 km away (Thomsen et 

al., 2006). This sound pressure level is similar to, but slightly less intense then, that used in 

naval sonar which has been implicated in the mass stranding of beaked whales (Thomsen et al., 

2006). During wind farm operation the noise from the turbines may be detectable for porpoises 

and seals up to about 1 km from the source (Thomsen et al., 2006). 

At the Nysted Wind farm the population of harbor and grey seals was monitored before, during 

and after construction. Wind farm operation did not seem to significantly impact seal 

abundance; however, piling driving operations that occurred at one foundation site (Nysted uses 

gravity foundations) did decrease the number of seals observed at a nearby breeding site. Also, 

while the total annual population remained stable, after construction fewer harbor seals were 

present on nearby land sites in June (the breeding season) but more were present in July and 
90

August. This could suggest that fewer seals are using the area around the wind farm for breeding 

which could have an important effect on the viability of the population (Carstensen et al., 2006). 

Harbor porpoises were shown to occur less frequently in the area around a wind farm during 

construction at both Nysted (Carstensen et al., 2006) and Horns Rev (DONG Energy et al., 

2006). Presumably this is primarily due to animals fleeing the noise. At Horns Rev, the 

porpoises seemed to return following the construction period; however, even two years later 

porpoises at Nysted are less numerous then they were in baseline studies (DONG Energy et al., 

2006). 

 

8.7.3. Impacts on Fish 

Wind farms could have both positive and negative impacts on fish. These effects could cascade 

up the food web to have either positive or negative effects on the birds and marine mammals that 

consume them. 

As with marine mammals, fish can be very sensitive to loud sounds and could be displaced 

during wind farm construction; however, there is a great deal of variability among fish auditory 

systems and different species of fish will respond differently to noise from underwater 

construction. Furthermore, bottom-dwelling fish will be affected differently from fish swimming 

in the water column due to the different propagation of sound through sediment (Thomsen et al., 

2006). 

There have been few studies on the effects of pile driving on fish (reviewed in Hastings and 

Popper 2005). In general, these studies have placed fish in cages at various distances from the 

piles being driven and measured mortality and other injuries through non-microscopic necropsy. 

Abbott and Bing-Sawyer (2002) studied Sacramento blackfish and found that fish placed in 

cages close to the sound source (45 m) experienced more damage than animals further away and 

that damage was only found in animals exposed to 193 dB or more. CALTRANS (2004) studied 

shiner surfperch and steelhead and compared damage between fish experimentally exposed to 

pile driving and fish that were transported to the site but not exposed to noise. They found that 

fish exposed to pile driving noise experienced more damage than unexposed animals, but that 

there was no significant difference in mortality rates between control and experimental animals. 

CALTRANS (2001) also conducted an observational study of fish mortality during pile driving 

for the San Francisco-Oakland bay bridge and found dead fish out to 50 meters around the 

construction. Finally, Abbott (2004) and Marty (2004) studied the effects of a relatively small 

pile (2 feet in diameter) being driven close (32 feet) to cages of shiner perch, Chinook salmon 

and northern anchovies and they used control fish subjected to the same conditions but without 

noise. They found no difference in either mortality or pathology. 

There have also been a few studies on the effects of noise on stress levels in fish. Chronic noise 

exposure is known to increase stress levels in humans with consequential effects on health. 

Smith et al. (2004) studied the effects of a continuous 170 dB noise on corticosterone (a stress 

hormone) levels in goldfish and found no statistically significant results. 
91

More subtle effects on fish behavior could also occur. Engas et al. (1996) and Engas and 

Lokkeborg (2002), found that the catch rate of haddock and cod decreased in areas after air gun 

use but returned to normal several days later suggesting that fish left the area and gradually 

returned. Nedwell et al. (2003) calculated the zones around which salmon and cod would show 

significant avoidance behavior to be 1.4 km and 5.5 km, respectively. 

The only clear conclusions which can be drawn from this research is that pile driving will effect 

fish; the degree of this effect will vary and is not at all clear. Very close to pile driving some 

mortality may occur for some species and fish may temporarily leave the area. 

Wind turbines also create noise during operation. This noise would be of very long duration and, 

if intense enough could have significant ecological impacts. However, under normal conditions 

operational wind farm noise has been shown to be slightly above background noise, generally by 

approximately 5 dB in British wind farms (Nedwell et al., 2007). 

Many species of fish are also sensitive to electric and magnetic fields which can be caused by 

buried underwater cables. Fish use their perception of electric and magnetic fields for 

orientation and prey detection. Species that contain magnetic material, potentially for 

navigational purposes include several species of economically important fish including yellow 

fin tuna, and Chinook and sockeye salmon (Öhman et al., 2007). There is some evidence that the 

fish in the area of the Nysted wind farm may be affected by the electromagnetic fields produced 

by the wind farm. Baltic herring, common eels, Atlantic cod and flounder all showed 

asymmetries in the catch rate on either side of the cables suggesting that the cables may retard 

migration (DONG Energy et al., 2006). 

In addition to these negative effects, there has been some discussion of the potential for positive 

impacts from offshore wind farms on fish and fisheries. After construction of an offshore wind 

farm, turbine foundations could act as fish aggregating devices (FADs). The foundations could 

add three dimensional complexity to the environment and serve as a substrate for benthic 

invertebrates, thereby attracting fish. Offshore oil platforms are well known for this property. 

Although monopiles lack the structure of offshore oil and gas platforms, Wilhelmsson et al. 

(2006) have shown that they act as fish aggregating devices at the Yttre Stengrund and 

Utgrunden wind farms. At the Horns Rev and Nysted wind farms there was no clear difference 

between fish densities inside and outside of the wind farms (DONG Energy et al., 2006). The 

difference in these results is likely due to the different methodologies employed. The Swedish 

studies used scuba divers to monitor fish while the Danish studies used hydro-acoustic sampling. 

As a result, the Danish studies may have overlooked some of the smaller species observed in the 

Swedish wind farms. 

8.7.4. Environmental Benefits of Offshore Wind Power 

Wind power is considered to be among the most environmentally benign sources of electricity 

available today and it is important to consider the negative environmental impacts of wind power 

in the context of alternative sources of electricity. For example, concerns about the impacts of 

wind power on birds should be compared to the impacts of fossil fuel use on birds on a per MW 

basis. 
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Greenhouse Gases

The primary environmental benefit of wind power is its negligible contribution to global climate 

change. The only greenhouse gases produced by the establishment of a wind farm are those used 

in the construction and operation of the wind turbines and farm. The greenhouse gases released 

from construction and operation of an offshore wind farm are likely to be dominated by CO2

released from the ships used in construction of the wind farm and the manufacturing of the steel 

and concrete used in the turbine towers and foundations. To our knowledge there is no estimate 

of these emissions for offshore wind farms, but for onshore wind farms these emissions decrease 

the CO2 offset by 1 to 2 percent (White and Kulcinski, 1998). It is not clear whether offshore 

turbines would have higher or lower per MW CO2 output from construction. In general, 

transportation via ship is more efficient than over land, but the operation and maintenance 

emissions may be higher for offshore wind. Assuming an offshore wind turbine replaces 

electricity generation from fossil sources at a rate equal to that for onshore wind farms, then each 

MW of wind capacity should displace about 1800 tons of CO2 per year (AWEA, 2008). 

It is extremely difficult to predict the effects of climate change per ton of CO2. While we can 

predict a per MW bird mortality associated with wind power, we cannot make a comparable 

prediction for fossil fuel use. Studies have indicated that climate change may be associated with 

high rates of species extinction. Climate change is predicted to cause between 11 and 45 percent 

of all species to become extinct (Thomas et al., 2004). For birds, the subject of so much concern 

over wind power, it is estimated that 950 to 1800 species of terrestrial birds (out of 8750 studied) 

will be threatened due (in part) to climate change (Jetz et al., 2007). It is critically important, 

however, that there has been very few studies of the adaptation of biodiversity to climate change, 

thus these estimates must be taken as preliminary (IPCC, 2007). Still, the fact that climate 

change may imperil the survival of species, especially species endemic to high and low altitudes 

and latitudes and restricted geographical ranges, is in contrast to wind power which has no 

demonstrated population or species level effects on biodiversity. 

Water

In many parts of the U.S. water resources are stressed. The six world climate models used in the 

Intergovernmental Panel on Climate Change (IPCC) generally predict that the U.S. will become 

drier by 2050. One of the models predicts that precipitation over virtually the entire U.S. will 

decline by over 30 percent while the other five models show more modest declines (IPCC, 

2007). Forty-eight percent of total water withdraws and nine percent of total water consumption 

(68 billion liters per day) is used by thermoelectric power plants (powered by coal, natural gas, 

nuclear, oil and biomass; USDOE, 2008a). Ethanol production also uses large quantities of 

water, from 3.5 to 6 liters of water for every liter of ethanol produced (Keeney and Muller, 

2006). Wind power directly uses no water. Per kWh, the amount of water used in fossil fueled 

plants ranges from about 0.2 to 0.6 gallons depending on the technology employed (Clean Air 

Task Force, 2003). Assuming a 40 percent capacity factor, one MW of offshore wind power can 

offset the use of between 0.7 and 2.1 million gallons of freshwater per year. 
93

Value of Ecological Benefits

Onshore and offshore winds have nearly identical ecological benefits on a per MWh basis. We 

can attempt to place a dollar value on the ecological services, in terms of water unused and 

carbon not emitted, of offshore wind power relative to traditional fossil fueled power. The actual 

costs of offsetting a ton of carbon are not known, but governments have set up trading systems in 

which offsets are exchanged. The costs of these offsets will be set by supply and demand, and 

are expected to increase in the future. Current prices for the offset of one metric ton of CO2 are 

around $30. Each MWh of coal-fired electricity produces 0.839 metric tons of CO2 (Sims et al., 

2003). Thus, per MWh, the value of avoided CO2 emissions may be about $25. 

8.8. Ecological Mitigation 

8.8.1. Mitigation through Site Selection 

Potential sites are avoided due to their potential impacts on the environment. Certain areas are 

known to be bottlenecks on the migratory routes of large numbers of birds. Cape May, New 

Jersey, Delaware Bay, Grays Harbor Washington, Point Reyes, California, and the Barrier 

Islands of Louisiana are all important areas for avian migration and may be considered 

unacceptable for offshore wind power development (Lincoln et al., 1998). Similarly, planners 

for the LIOWP took the migration routes of Right Whales into consideration in selecting a site. 

Whale migration routes will likely need to be considered on the Pacific coast as well. 

Placing offshore wind farms near nesting sites for seabirds may also be ecologically hazardous. 

Seabirds generally avoid using the Horns Rev wind farm and direct mortality from collision with 

turbines is relatively rare and in many cases not significant. However, because seabirds avoid 

entering offshore wind farms, their existence may reduce available foraging habitat or force birds 

to expend energy to fly around the wind farm (Desholm and Kahlert, 2005). Both of these could 

have population level impacts on bird species. Offshore wind farm construction could also have 

similar impacts on nearby populations of marine mammals. 

From the perspective of conserving biodiversity, it is perhaps most important for developers to 

avoid areas considered essential habitat for threatened or endangered species. The Endangered 

Species Act requires that critical habitat for any listed species be identified and it requires federal 

agencies that permit activities consider the effects of permitting on these habitats. While there 

are procedures in which the government may permit activities that are detrimental to the critical 

habitat of an endangered species, it would seem prudent for developers to exclude critical 

habitats of endangered species from development plans, if not out of a perceived ethical 

responsibility for conservation, then out of the risk of the failure of the permitting process and 

the associated financial losses. 

The areas of critical habitat for species managed by NOAA are listed at 

http://www.nmfs.noaa.gov/pr/species/criticalhabitat.htm and species managed by FWS are listed 

at http://crithab.fws.gov/. The critical habitat of the North Atlantic Right Whale and the Stellar 

Sea Lion, both managed by NOAA, are the most likely to influence offshore wind placement. 

The critical habitat of the North Atlantic Right Whale includes areas off the coast of southern 
94

Georgia and the Atlantic Coast of Northern Florida as well as areas off the Northern and Eastern 

coasts of Cape Cod. The areas of critical habitat that may conflict with offshore wind power 

development for the Stellar’s sea lion consist of five small zones off the coast of Northern 

California and Southern Oregon. 

The impacts on local culture should also be considered. One of the primary criticisms of the 

Cape Wind project is that it will spoil the views from historic areas. Similarly, some areas of 

interest for offshore wind development may be located near shipwrecks. These issues should be 

noted by wind power developers for two reasons. First, the BOEMRE, in their guidelines on 

development of the OCS, adopted a policy of consulting with State Preservation Authorities 

before permitting development and it is therefore possible that BOEMRE would decline a permit 

for offshore wind energy if there were significant cultural issues. Secondly, even if BOEMRE 

were to allow development, construction can be seriously slowed by local community resistance. 

For example, the Cape Wind project will, if completed, have taken at least a decade to develop 

and have required at least one protracted legal battle (Alliance to Protect Nantucket Sound v. 

United States Army). In contrast, WEST’s plans to build a wind farm off the coast of Texas have 

proceeded rapidly, despite less favorable wind conditions. This may be due to acceptance by the 

local community, many of whom are familiar with offshore structures from experience with the 

oil and gas industry (Patterson, 2005). 

8.8.2. Mitigation through Technology 

 

Most of the offshore wind turbines constructed to date have used monopole foundations. The 

ecological effects of the piling operations are a concern; however, there are alternatives to piledriven foundations. One option would be to use gravity foundations, as were used in the Nysted 

and Middlegrunden wind farms. Gravity foundations are simple concrete structures with large 

diameter bottoms that rest on the sea floor. They weigh thousands of tons and use their weight to 

stabilize the turbine. Gravity foundations do not require piling operations and therefore have less 

potential to disturb marine mammals and fish. Also, gravity foundations have more three 

dimensional structure than monopiles; this may provide additional habitat for benthic organisms. 

Another alternative would be to use suction foundations, such as those considered in the Beatrice 

demonstration project. Suction foundations are simple steel baskets that are placed on the 

seafloor and form a seal with the ocean bottom. Suction is then applied to the inside of the 

basket and the resulting pressure difference causes the basket to bury itself in the sediment, much 

like a driven monopole (Byrne et al., 2002). Again, installation is much quieter allowing for 

fewer environmental effects. 

Technologies are also being developed to allow the use of deeper water. Using deeper water 

would allow offshore wind farms to be sited further from shore, increasing the wind speed and 

decreasing the possibility of conflicts with local human and animal populations. A survey 

conducted in New Jersey showed visitors and residents simulated images of offshore wind farms 

at varying distances from shore and found that as the distance increased the percentage favoring 

development increased (Mills and Rosen, 2006). Deep water turbines could be placed over the 

horizon and thus be invisible from shore. This would also decrease their impact on seabirds 

which generally do not feed in the open ocean, and on migratory birds, which, with the exception 
95

of birds flying over the GOM, do not migrate over open ocean. Additionally, these turbines are 

placed on floating foundations that will likely have fewer environmental impacts during 

construction. 

One of the leading developers of floating foundations for offshore wind turbines is Blue H 

Technologies. They have recently installed an offshore wind turbine in 108 meters of water 20 

km off the coast of Italy and also applied to BOEMRE for a permit to study the potential for a 

wind farm 23 miles off the southern coast of Cape Cod (Blue H, 2009). If this technology 

becomes economically viable it could decrease conflicts with coastal communities and would 

lessen the environmental impacts of wind farms. 

8.9. Conclusion 

The higher economic costs of offshore wind power relative to onshore wind power could be 

justified if the ecological or social costs of offshore wind were significantly different from 

onshore wind power, but this seems not to be the case. Both on- and offshore wind power face 

local opposition due to user conflicts. The ecological impacts of offshore wind power affect a 

very different ecosystem than onshore wind power and, as a result, their ecological impacts are 

not directly comparable. However, like onshore wind, it is clear that offshore wind power does 

have ecological impacts with the potential for population level effects. 

Decreasing commodity costs or legislation capping greenhouse gas emissions could increase the 

profitability of offshore wind but would not change the fact that onshore wind will be a less 

expensive alternative, even when transmission costs are included. Until land use conflicts in 

high wind onshore sites become severe, or the technology develops so that the higher offshore 

winds balance the higher costs of installation, there seems to be little incentive for a large 

offshore wind industry in the U.S. In sum, we do not envision offshore wind producing a 

significant portion of the U.S. electricity production until at least 2020. 

It is much more difficult to analyze the ecological and economic costs and benefits of offshore 

wind power relative to fossil-fueled power. Including a premium on coal-fired power of 

$25/MWh to offset emissions may make coal and offshore wind power nearly price competitive, 

depending on the specific capital costs of offshore wind. This $25/MWh premium would give 

coal and offshore wind similar greenhouse gas emissions; however, coal would still use more 

water than offshore wind and would be associated with significant health effects through 

particulate emissions and additional ecological impacts through sulfur emissions. However, this 

would be balanced against the ecological impacts of offshore wind in terms of bird and bat 

mortality and marine mammal impacts, which possibly can be mitigated. Thus, it is not clear 

that offshore wind is preferable to coal fired power, even if the emissions from the coal plant are 

offset. To make such a comparison would require valuing the health and acidification impacts of 

coal fired power against the environmental impacts of offshore wind, something that is beyond 

the scope of the present work. 

 

Based on the analysis in this chapter, it seems clear that the economic and ecological costs of 

offshore wind power are site specific. These costs can be mitigated with current technology and 

detailed site selection. It therefore seems imprudent to conclude that all offshore wind 
96

development is inferior to all onshore wind development or fossil fueled power. Instead, a more 

nuanced approach which weighs the site specific costs and benefits of offshore wind power is 

necessary. In some cases, offshore wind power may be able to cheaply produce electricity with 

negligible environmental impacts; however, in many more cases, offshore wind power will be 

more expensive than its competitors, even when the costs of carbon offsets are included. 
97

9. REVIEW OF OFFSHORE WIND POWER REGULATORY ISSUES 

In this chapter, we discuss the ways in which regulators could encourage the development of an 

offshore wind power industry that is economically viable and that considers the ecological costs 

and ensures public benefits. This chapter does not deal with the various laws with which a 

regulatory system would have to comply; for these issues we direct the reader to Santora et al. 

(2004) or Firestone et al. (2004). While it will be a challenge for regulators and developers to 

negotiate this complex milieu of already existing laws and regulations, we focus on the leases for 

offshore wind and their regulations. We first discuss the relevant European regulatory and lease 

frameworks for offshore wind power and then describe three relevant leasing systems in the U.S. 

We use these descriptions to discuss issues and tradeoffs involved in the development of an 

alternative energy leasing policy on the OCS. 

9.1. Introduction 

Onshore wind energy is experiencing rapid growth in the U.S. and around the world (Wiser and 

Bolinger, 2008) and offshore wind energy development is experiencing rapid growth in Northern 

Europe, yet despite significant potential, there are currently no offshore wind parks in the waters 

of the United States or Southern Europe. In part, this is due to the superior winds and shallow 

waters of the Baltic and North Seas, and the subsidies offered by European governments to 

offshore wind developers. The lack of a comprehensive regulatory system in the U.S. and 

several European countries may also be slowing development. 

Several European countries as well as some U.S. coastal states and the U.S. federal government 

are currently developing regulations for offshore wind power. In U.S. federal waters, the 

BOEMRE is the lead agency in coordinating offshore wind development. The Energy Policy 

Act of 2005 gave the BOEMRE authority to lease offshore wind energy on the OCS. In 

December 2007, BOEMRE published its record of decision (ROD) in response to the 

programmatic Environmental Impact Statement (EIS) on alternative energy uses on the OCS 

(Luthi, 2007), and in July 2008, BOEMRE proposed regulations for an offshore alternative 

energy program and asked for public comments. 

When establishing a regulatory system it is often difficult to quantify the costs and benefits 

involved and to create a system that is comprehensive, yet flexible and robust to future 

uncertainty. All regulations are a series of tradeoffs in which regulators must balance conflicting 

policy goals and uncertain outcomes. In the case of offshore wind, regulators must balance 

encouraging a low-carbon, renewable energy technology with impacts to local ecosystems and 

viewsheds and potential conflict with other offshore users (Bisbee, 2004). Each regulatory 

decision will either encourage or discourage offshore wind development and could affect the rate 

of development and its eventual scale. 

The regulatory system most applicable to offshore wind energy may be the regulation of the 

offshore oil and gas industry since in both cases private developers seek to produce energy, a 

commodity needed by the public, through the use of public marine resources. However, there 

are significant differences between these two industries. In the offshore wind industry, 

developers must take out large loans and spend several years before any revenue is generated. 
98

When they do begin generating income, the income will be spread out slowly over many 

decades, and the risk to revenue stream can come from many sources- environmental, market and 

regulatory. The difference between the cost and sales price of offshore wind energy is quite low. 

In contrast, the offshore oil industry, although requiring significant capital, generally produce 

large amounts of revenue quickly and recoup initial investments within the first few years of 

production. Additionally, while the price of oil is highly variable, the ratio of sales price to cost 

is far higher than it is for offshore wind energy. As a result, regulations, especially the 

production of site specific EISs and lease fees that may have little impact on the oil and gas 

industry, could cripple the offshore wind industry (Schellstede, 2008). 

The major issues regulators will have to address include: 1) lease terms and conditions, including 

phases of development rights, lease fees, and the length of leases; 2) competition and the 

approval process, including how to select sites and what criteria to use in permitting leases; 3) 

environmental impact assessments, including data requirements and alternative methods for 

NEPA compliance; 4) monitoring operational issues, including safety and environmental 

compliance; and 5) ensuring decommissioning. A brief synopsis of the ways in which several 

regulatory authorities have dealt with these regulatory issues is summarized in Table I.1. 

9.2. Regulatory Systems in Europe 

Many European nations have either no method for regulating offshore wind farms or have little 

successful experience in promoting their development. The UK and Denmark are two 

exceptions. They both have several large operational offshore wind farms and have several 

others under construction and in planning stages. In this section we review the regulatory 

regimes of these two nations along with two other nations, Germany and the Netherlands. Both 

Germany and the Netherlands have less formalized offshore wind regulations which allow 

developers more freedom but which have so far resulted in relatively few operational wind 

farms. 

9.2.1. United Kingdom 

The submerged land of the United Kingdom’s territorial sea is the property of the Crown Estate 

(Scott, 2006). As a result, the Crown Estate must grant a lease for offshore wind development 

within the UK’s territorial sea. Beyond the territorial sea, the Crown Estate must still grant a 

license for development. While the Crown Estate is the landowner, the Department of Business, 

Enterprise and Regulatory Reform (BERR), formerly Department of Trade and Industry, is the 

lead government agency involved in offshore permitting (Peloso, 2006). 

The Crown Estate has thus far conducted two “rounds” of leasing. The first round took place in 

April 2001 and resulted in 18 agreements between the Crown and energy developers. The 

second round took place in December 2003 and resulted in 15 agreements (The Crown Estate, 

2008). A third round was announced in June 2008 (Smith, 2008). In all rounds, the agreements 

were only with the Crown Estate and developers had to obtain permits with other government 

agencies (Peloso, 2006; Scott, 2006). In the first round, developers were required to choose sites 

of interest. In the second round, developers were required to submit proposals that fell within 

one of three strategic areas designated by the government, areas for which a Strategic 
99

Environmental Assessment (SEA; similar to U.S. Programmatic Environmental Impact 

Statement) had been completed.24 

In order to participate in the round two leasing process, companies registered by submitting a 

ten-page business development plan which included potential areas of developmental interest. 

The Crown Estate sent instructions for tenders to registered companies. The companies then 

submitted tenders composed of financial information, a description of the project, a 50 page 

business development plan and a decommissioning plan (The Crown Estate, 2008). This entire 

process took about 9 months to complete. 

The Crown Estate used four criteria to evaluate tenders including the financial and technical 

capacity of the applicant, the development plan (i.e. what the applicant was offering), the 

business development plan, and the decommissioning plan. The highest weight was given to the 

business plan which included financial plans, plans for obtaining other required permits, and 

plans for construction and operation. This section of the tender was to form the basis of the 

legally binding lease. The development plan also included a description of the environmental 

site specific studies the applicant would conduct in the creation of the SEA. Priority for 

competing applications was given to the most qualified applicant; financial considerations from 

the perspective of the Crown were not considered. Instead flat rate fees were used. All 

applicants were required to pay an application fee of £2,500. If applicants were successful they 

were required to pay a one-time option fee of £25,000 to £500,000 depending on the size of the 

development and roughly equal to £2,000 to £5,000 per km2

. This option fee was used to 

support research and education projects committed to the furtherance of the offshore wind 

industry (The Crown Estate, 2008). 

Leases provide developers seven years to obtain other necessary consents. In addition to the 

Crown Estate, developers must obtain a permit from the BERR for any electrical generating 

project over 1 MW in capacity (DTI, 2004). In its permitting decision, BERR primarily 

considers the navigational issues raised by wind farms. BERR may not grant a permit in any 

area essential to international navigation and must consider the cumulative impacts of other 

permitted wind farms on this decision. BERR also has the authority to close the area in and 

around a wind farm to public navigation. 

Offshore wind projects require licenses from the Marine and Fisheries Agency (MFA). The 

MFA is the agency tasked with evaluating the environmental impacts of a proposed wind farm 

by executing the provisions of the Food and Environmental Protection Act (FEPA) and Coast 

Protection Act (CPA). The MFA issues guidance on the requirements for a SEA, which must be 

completed before MFA approval (DTI, 2004). MFA evaluates hydrological effects, effects on 

fisheries and other marine life, and effects on specially designated habitat. 

BERR is also responsible for ensuring decommissioning of offshore structures. The developer 

must submit an acceptable decommissioning plan to BERR. The decommissioning plan may 

make allowances for repowering or reuse of facilities for other renewable energy generation. 

The decommissioning plan may leave some components in place (buried cables, monopiles, 

 

24 As a result of the SEA, BERR removed any area within 8 km of the coast, as well as any shallow water, from 

consideration for wind development. 
100

scour protection) if removing them would cause an undue ecological or economic burden (DTI, 

2006). BERR requires that the developer provide some financial assurance that 

decommissioning will occur according to the agreed upon plan. BERR will accept financial 

assurances on a case-by-case basis, but generally accepted assurances include cash, surety bonds, 

or letters of credit. Liability for damages from the remnants of a decommissioned wind farm 

will remain with the owners in perpetuity. 

BERR did not publish its plan for decommissioning until late 2006, well after several offshore 

wind parks were operational. This, combined with the changes between the first two rounds of 

offshore leasing, suggests that the UK continues to modify its regulations as the industry 

develops. 

Thus, in the UK there are three main agencies, the Crown Estate, the BERR and the MFA, each 

of which are tasked with evaluating different components of offshore wind development. This 

system has been thought of as too complex and inferior to a “one-stop shop” approach set up by 

Denmark (EWEA, 2007; Firestone et al., 2004); however, the UK offshore wind industry seems 

to be developing well despite this criticism. 

9.2.2. Denmark 

Denmark has been leading the world in wind power usage for centuries and they continue to do 

so, especially in the offshore environment. Denmark established the world’s first offshore wind 

farm at Vindeby in 1991, and the second at Tuno Knob in 1995. They also established the first 

commercial scale offshore wind farm at Middelgrund in 2001 (see Chapter 8). 

One reason for the success of the offshore wind power sector in Denmark is government policies 

on offshore wind power. Offshore wind development in Denmark is regulated almost 

exclusively by the Danish Energy Authority (DEA). This is different from many other countries 

in which offshore wind developers have to interact with a variety of governmental agencies. The 

DEA provides “one-stop shopping” for wind energy developers (DEA, 2007) and provides 

centralized planning and coordination for the promotion of offshore wind power. 

The methods for gaining DEA approval have evolved over the past several years, but proceed 

through either a tender or open-door process. In the tender process, the DEA requests proposals 

for tenders at a specific site that has been pre-screened by DEA and the DEA releases a desired 

capacity. Interested applicants are pre-qualified based on financial, legal and technical 

qualifications. Pre-qualified applicants are asked to submit tenders for a wind farm of specific 

capacity. The tenders are evaluated primarily on the basis of the feed-in price required for the 

project. The winner of the tender process must then complete an EIS and may complete 

preliminary studies. However, this requirement can be waived if a satisfactory EIS has already 

been conducted in the site selection process. The winning bidder is obligated to build the wind 

farm (DEA, 2007; Peloso, 2006). 

The open-door process involves an interested party applying to the DEA for a permit without a 

specific request by DEA and outside of the areas that have been pre-screened by the DEA. After 

the DEA receives the application, they will invite other interested companies to apply for the 
101

development of the same area, ensuring competition. As before, an EIS is conducted by the 

applicants. The DEA has so far not implemented the open-door process (DEA, 2007; Peloso, 

2006). 

The feed-in prices can be quite high. The recent Rodsand II agreed upon feed in price of 

electricity is 13.2 ¢/kWh. The Rodsand lease lasts for 25 years and includes a permit to conduct 

preliminary studies as well as a permit to build and operate a wind farm. The time between the 

request for tenders and the deadline for submitting tenders can be quite short; in the Rodsand 

case it was just under two months (DEA, 2008). 

There is no national codification of operational issues. Instead, the winning bidder is required to 

submit safety, decommissioning and environmental monitoring plans and is then required to 

carry out these plans. The developer is also required to submit an annual report summarizing the 

environmental studies carried out that year (DEA, 2008). 

9.2.3. The Netherlands 

The Dutch have set a goal of offshore wind farms with a total capacity of 6000 MW. Unlike the 

UK and Denmark, the Dutch set specific areas in which offshore development is excluded. 

Interest in a wind farm is initiated by the developers who send a proposal to the Ministry for 

Transport, Public Works and Water Management (Mast et al., 2007). The ministry replies with 

guidelines for the permit request and makes the proposal public. The permit request must 

include plans for construction, decommissioning, and an EIS. If granted, the permit allows the 

developer two years to complete construction. Additional permits for running cables to shore 

and across the shore are also required. 

In the Netherlands developers are not pre-qualified; however, the requirement to complete 

construction within two years and the need for an EIS are intended to discourage speculation. 

The first-come, first-served method of awarding licenses virtually eliminates competition for 

sites. There is no competition among proposals which best serve the national interest, instead, 

the only competition is to be the first to submit a suitable application. The Dutch do not institute 

fees for leases, but developers must pay for the EIA; again this is thought to discourage 

speculation (Mast et al., 2007). 

In 2006, the Dutch had a subsidy for offshore wind projects of 0.097 € ($0.15) per kWh. 

However, the Dutch government decided that their renewable energy goal would likely be met 

without the subsidy and were worried that the subsidy would cost too much given the growing 

interest in offshore wind. Therefore, they set the subsidy to zero in late 2006 (Mast et al., 2007). 

In late 2007 and early 2008 the Dutch government developed a new renewable energy premium 

program in which renewable electricity generators are paid a premium over the first ten years of 

operation. The premium depends on the technology used and the price of electricity and has not 

been codified for offshore wind, but for onshore wind it is €0.028 ($0.044) per kWh (EREC, 

2007a). 
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9.2.4. Germany 

Germany has permitted more offshore wind parks than any other European state, but no wind 

farms are currently operational in German waters. In Germany, the provinces control the waters 

up to twelve miles from the shore while the federal government controls the rest of the Exclusive 

Economic Zone (EEZ). Most offshore wind projects in Germany are expected to occur in federal 

waters; however, as in the U.S., the German states will have input in the permitting process, 

especially the permitting of transmission cables (BSH, 2008). 

Offshore wind project approval in Germany is a non-discretionary action of the German Federal 

Maritime Agency (Bundesamt fur Seeschiffahrt und Hydrographie, BSH). That is, German law 

prescribes conditions for the rejection of offshore wind projects. The only duty of the BSH is to 

determine if those conditions exist. If they do not, the developer has a legal right to develop the 

project (BSH, 2008). These conditions are that the project does not constitute a danger to 

navigation and does not pose an unacceptable risk to the environment. 

The consent procedure begins with the developer submitting an application to BSH. BSH then 

solicits comments from other government agencies, principally the regional waterway and 

shipping authority which also has to give regulatory approval. There is then a second round of 

comments solicited from a larger group of stakeholders including the public. After this second 

round of commenting the developer is invited to hold a conference in which the developer 

presents their plans for development and the scope of the required environmental data is 

determined. The developer conducts an EIS and an analysis of the potential danger to navigation 

caused by their proposed wind farm. After receipt of these documents, BSH passes them along 

to other relative authorities and makes them available to the public. BSH then decides if the 

proposal meets its criteria. At the same time, regional waterway and shipping administrators 

determine if the project poses a threat to navigation (BSH, 2008). 

If the project is approved by both the BSH and the regional waterway and shipping authority, 

BSH approves the project for a term of 25 years. Construction must begin within 2 1⁄2 years and 

the developer must furnish a bond for decommissioning (BSH, 2008). The developer is 

guaranteed a fixed price for electricity under the feed-in-tariff which starts at about 9 euro cents 

($0.14) per kWh (EREC, 2007b). The price declines slowly over time. 

There are no allowances for competition in the German system. If two developers submit 

applications for the same area, the first complete and acceptable application is granted (BSH, 

2008). 

The German system has been successful in permitting offshore wind projects, but thus far, 

dismal in their construction. This could be due, in part, to the fact that the only competition is to 

be the first developer with an acceptable development plan. Thus, developers have an incentive 

to complete applications for as many areas as possible, as quickly as possible. 
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9.3. U.S. Programs 

Two conceptual models for the regulation of offshore wind power are presented in Figures I.1 

and I.2 and represent the regulatory scheme for offshore wind energy in Texas (Figure I.1) and 

the Bureau of Land Management’s (BLM) regulatory structure for onshore wind (Figure I.2). 

These models depict two ends of a spectrum of methods of regulation. Their main differences 

are whether the government or the developers choose the sites for development and if the 

government seeks to encourage competition among developers for the maximum financial 

benefit to the public (USDOI, BLM, 2006; Texas General Land Office, 2007a). 

The fact that two very different programs were developed nearly simultaneously in the U.S. 

suggests that there are a number of feasible options for regulation. One reason for the difference 

between these two regulatory frameworks could be the relative interest in profit of the two 

agencies. The BLM stated that the development of onshore wind resources should have little 

budgetary impact and that their primary purpose is not to generate income for the government 

but to encourage wind energy development, consistent with the Energy Policy Act of 2005. The 

State of Texas also seems interested in the development of an offshore wind energy industry; 

however, they seem to be equally interested in maximizing the monetary benefit to the state 

(Patterson, 2005). 

9.3.1. BLM Guidelines 

The BLM manages wind energy development on federal land. In 2003 they began the process of 

conducting a programmatic EIS. The EIS was released in June of 2005 and an Instruction 

Memorandum implementing the Record of Decision was published in August 2006 (USDOI, 

BLM, 2006). 

The BLM policy is designed to encourage the “development of wind energy in acceptable areas” 

(USDOI, BLM, 2006). Applicants may apply for a right-of-way for either a single 

meteorological tower, a series of meteorological towers in a larger area or commercial 

development. Applications for testing are conducted on first come basis (i.e. not competitively) 

and competing applicants for commercial energy development will be encouraged to form a 

cooperative agreement. Competitive leasing may occur if deemed appropriate in specific areas 

(USDOI, BLM, 2006). 

A right-of-way for a single meteorological tower will last for three years and cannot be extended. 

The rental fee is $50 per year. The right-of-way does not establish any preferential rights to 

future wind energy projects in the area, and BLM may authorize multiple right-of-ways in the 

same area to multiple parties. The applications for meteorological monitoring should be 

processed within 60 days and are subject to minimal cost recovery fees (USDOI, BLM, 2006). 

A right-of-way for a larger site lasts for three years but has provisions for extension beyond the 

three year limit. The right-of-way precludes other wind energy development in the area over the 

three year term of the lease. However, the holder establishes no right to commercially develop 

the area. As part of the application approval, BLM may consult with the National Renewable 

Energy Lab to determine if the proposed number and location of monitoring sites is sufficient to 
104

accurately predict future wind conditions. If BLM determine that the application will adequately 

quantify the wind resource, then a NEPA process begins. The rental fee will be determined by 

the total project area (i.e. the area that excludes competing development) and will be $1 per acre 

or $1000, whichever is greater. Bonds are discretionary, and data collected is proprietary, but 

may be made public if the holder applies for commercial development rights (USDOI, BLM, 

2006). 

The right-of-way for commercial development is not term-limited and is expected to last at least 

30 years. The BLM retains the right to permit other compatible land uses over the term of the 

lease. The rental fee is $2,365 per MW of capacity per year and is phased in over the first three 

years of the project. This rate is designed to be a 3 percent royalty on production, assuming a 30 

percent capacity factor and a 3 ¢/kWh sales price. It should be noted that the assumed 3 ¢/kWh 

sales price is below the average sales price of wind generated electricity (Wiser and Bolinger, 

2008), and as a result the royalty is actually less than 3 percent. The royalty should add about 

0.09 ¢/kWh to the cost of generating electricity (USDOI, BLM, 2006). 

To ensure that speculators do not unduly control wind resources, applicants are required to 

provide information on their technical and financial capabilities. Additionally, the facilities for 

the monitoring of a wind resource must be constructed within 12 months of the approval of the 

application and the construction of wind turbines must commence within 2 years of the approval 

of an application (USDOI, BLM, 2006). 

The NEPA process for BLM wind energy decisions will generally end with either categorical 

exemptions (CX) or environmental assessments (EA). CXs may be applicable for site 

monitoring applications while environmental assessments, building off of the programmatic EIS 

developed by BLM will be sufficient for most wind farms unless there is either significant public 

controversy or a determination of significant adverse impacts. Additionally, it would be 

acceptable to consolidate local and state environmental reviews with the NEPA process (USDOI, 

BLM, 2006). 

9.3.2. Texas Offshore Wind Program 

Because of its Spanish history, Texas’ waters extend 3 marine leagues (9 nautical miles) offshore 

of the Texas coast (as opposed to 3 nautical miles for most other states; Florida’s waters also 

extend three marine leagues while Louisiana’s extend three imperial miles, slightly more than 

three nautical miles). As a result, Texas has been able to develop its own offshore wind leasing 

program which has evolved over the past several years. In 2005, the Texas General Land Office 

(GLO) signed an agreement with Galveston Offshore Wind (a subsidiary of WEST) for an 

11,355 acre lease seven miles off the coast. In 2006, the GLO signed an agreement with 

Superior Renewable Energy (later a subsidiary of Babcock and Brown) for a 40,000 acre lease. 

Neither of these leases were conducted competitively. However, in October 2007, the GLO 

conducted a competitive leasing program and awarded WEST leases on four tracts of land 

totaling 73,000 acres. WEST was the only bidder, although there was interest from one other 

firm (Schellstede, 2008). The terms of both the competitive and non-competitive leases were 

similar, with the major difference being an increase in land rental rates from $10,000 to $20,000 
105

per tract per year during the site testing and construction phases (Texas General Land Office, 

2007a and b). 

In the recent competition, the GLO released a set of bidding instructions stipulating which areas 

were available for lease, the minimum size (in MW) of the development and the minimum 

royalty rates. The GLO stated that the winning bidder would be the highest bidder that met or 

exceeded the minimums. The minimum lease rates were $20,000 per year during site testing and 

construction, then a gradually phased in royalty that varied from 3.5 to 5.5 percent of gross 

revenue. There was also a stipulation that set minimum annual royalties on a per MW of 

installed capacity basis which would apply only if they were greater than the royalties as a 

percentage of gross revenue (Table I.2). The term of the lease was 30 years (Texas General Land 

Office, 2007a and b). 

 

The lease allows for phased access in which the lessee is first given research rights and then 

granted construction and operation rights. Within 60 days of the start of the lease, the lessee 

must submit a research plan to the GLO for approval. This must include a description of 

environmental studies and environmental assessment which the developer will undertake. After 

this initial research plan, the lessee must submit a quarterly Phase 1 progress report to the GLO, 

then submit a final report and a production plan to the GLO. The production plan must contain 

language that affirms that the lessee will either conduct an EIS if required by the Army Corps of 

Engineers, or else submit a mitigation plan to the GLO. In addition the production plan must 

contain economic analyses, the construction schedule and a final description of the project. Once 

the production plan is approved, the lessee may begin construction. During construction the 

lessee must submit progress reports to the GLO quarterly and the lessee has 36 months to 

complete construction (for the first 250 MW of capacity). Thus, the initial competition and lease 

gives the lessee the rights to both site assessment and development (Texas General Land Office, 

2007a and b). 

The lessee is required to provide the GLO with either a surety bond, a letter of credit, or a cash 

deposit before undertaking construction. The lessee sets the price of this bond, with approval 

from the GLO. The lessee owns all improvements on the site; however, the GLO has the right to 

receive the turbine foundations for use as artificial reefs upon cessation of production (Texas 

General Land Office, 2007a and b). 

The lease contains stipulations whereby the lessee is exempted from payments in the case of 

Force Majeure. The lease does not include stipulations for repowering of the site (Texas General 

Land Office, 2007a and b). 

9.4. BOEMRE Regulations 

9.4.1. Lease Terms 

BOEMRE released final regulations in April 2009 (USDOI, MMS, 2009). The regulations 

consist of a two tiered system in which developers can apply for either a limited lease or a 

commercial lease. A limited lease would be term limited to 5 years and would confer no 

developmental rights nor any preference for later commercial leases. BOEMRE anticipates that 
106

limited leases will primarily be used for technology evaluation and does not advocate their use 

for commercial operations. 

Commercial leases would be for 30 years and would include a 6 month planning period, a 5 year 

assessment period and a 25 year construction and production period. The developer would be 

allowed to cancel the lease if site assessment showed the lease area to be insufficient for 

development and would be required to submit a site assessment plan at the beginning of the lease 

and a construction and operations plan in order to proceed to the commercial development phase 

of the lease (USDOI, MMS, 2009). 

BOEMRE will collect two types of payments from commercial leaseholders, a rental fee of $3 

per acre and a royalty of 2 percent of estimated gross revenue phased in over the first two years 

of operation.25 In addition to royalties and rental fees, BOEMRE may also charge processing 

fees on a case-by-case basis. This may be particularly likely in the case of site-specific EIS 

(USDOI, MMS, 2009). 

9.4.2. Competition and Approval Criteria 

The lease process would begin with BOEMRE gauging competitive interest in a site. BOEMRE 

may begin this process by issuing a call for information and nominations of areas to be leased, or 

may identify an area that a developer has expressed interest in. If BOEMRE issues a call for 

nominations it will then evaluate the nominations, determine the area to be leased and issue a 

sale notice. The sale notice would notify the public of the lease location, invite interested parties 

to submit lease applications, and would specify how competing applications will be judged 

(USDOI, MMS, 2009). 

If there is competitive interest, BOEMRE will conduct an auction. Commercial leases would be 

evaluated based on either the size of a cash bonus bid or the royalty rate. One of the two 

variables would be fixed to allow for straightforward comparisons. Limited leases would be 

evaluated only on the basis of a bonus bid. BOEMRE would not consider the technical or 

economic feasibility of competing projects, nor would it dictate the electrical capacity of 

development. BOEMRE will conduct competitions through either a sealed, single round bid 

process, a live or electronic auction, or some combination of these methods. In the oil and gas 

leasing system, sealed bidding is the dominant auction method (USDOI, MMS, 2009). 

If there is no competing interest, BOEMRE will issue a noncompetitive lease through a 

negotiation process (USDOI, MMS, 2009). 

 

25 Limited lessees would only pay the rental fee. BOEMRE studied the effects of this proposed rate by simulating 

73 offshore alternative energy projects. They found that 55 of the 73 projects would be economically viable, and 

that economic viability was unaffected by the proposed rate. They conducted a similar analysis of three hypothetical 

offshore wind farms built in 2010 or 2020 and found that the government’s share of net revenue was 40 percent for 

the wind farms constructed in 2010, but 15 percent for those constructed in 2020. Finally, BOEMRE compared the 

revenue to the government through rent and royalties to the Production Tax Credit (PTC). They found that the 

royalties they assessed reduced the value of the PTC by at most 15 percent (USDOI, MMS, 2009). 
107

9.4.3. Environmental Analysis 

BOEMRE will generally conduct two stages of environmental analysis. For both noncompetitive leases and competitive leases there will be an initial NEPA review during the 

issuance of a lease or lease sale and based on a site assessment plan. After the 5 year site 

assessment plan, lessees will be required to submit a construction and operations plan triggering 

a second NEPA review. Finally, two years before the end of the lease, the lessee must submit a 

decommissioning plan, which will again trigger a NEPA review (USDOI, MMS, 2009). 

For commercial leases, BOEMRE will conduct a site specific EIS before allowing activities to 

commence. It is possible that in the future EAs may be more widely used for NEPA compliance 

(USDOI, MMS, 2009). 

9.4.4. Operation 

BOEMRE will take an adaptive management approach to regulation and will allow operators to 

validate their own performance. BOEMRE will require developers submit detailed safety and 

environmental monitoring plans and self-report on their compliance annually. BOEMRE will 

request that developers submit data on air quality, monitor the incidental take of threatened and 

endangered species and marine mammals, demonstrate the training of personnel, and conduct 

annual facility inspections to ensure compliance with to be developed standards. BOEMRE will 

also require operators to submit incident reports in the event of injuries or damage to facilities. 

BOEMRE will conduct both scheduled and unscheduled inspections of facilities to ensure 

compliance (USDOI, MMS, 2009). 

9.4.5. Decommissioning 

BOEMRE has recognized that large scale decommissioning will not occur for several decades 

and may change regulations to reflect future technological changes. Operators will have to 

furnish a surety bond for decommissioning. The size of the bond will be determined on a caseby-case basis. Operators will also have to submit a decommissioning plan 2 years before the end 

of the lease and must complete decommissioning within 2 years of the end of the lease. 

Operators will have to remove all structures to a depth of 15 feet below the mud line, similar to 

the requirement for oil and gas structures and wellbores. BOEMRE may authorize facilities 

remain in place on a case-by-case basis (USDOI, MMS, 2009). 

9.4.6. Supplemental Bonding

Supplemental bonds are required in the GOM for leases that do not meet a minimum financial 

threshold. For offshore wind operations, it is conceivable that the Federal Government will 

require financial assurance to ensure that structure removal and site clearance operations will be 

performed in the event the operator goes bankrupt. For oil and gas structures that are 

transformed into an offshore wind site, the supplemental bond will be similar to existing 

requirements as described in Kaiser and Pulsipher (2008) except that P&A requirements will 

likely have already been performed. 
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9.5. Regulatory Issues 

9.5.1. Lease Terms 

 

Length of Lease

In order for a regulatory system to allow for development to occur, the length of the lease must 

be long enough for companies to recoup their initial investment, which, in the case of offshore 

wind power, can be quite high. Lease durations of 30 to 50 years are generally preferred by 

industry (AWEA, 2006; Hobson, 2006) and are being used in the UK. A lender is unlikely to 

allow for a loan to be financed for a term longer than the term of a lease. Therefore, long leases 

allow developers to finance loans over longer periods, reducing annual payments. In addition, 

long leases allow developers to delay decommissioning as long as possible. The technologies 

and regulatory options available for decommissioning may change as the first wind farms are 

removed and it is possible that the costs of decommissioning may fall as learning occurs, but the 

use of marine vessels will always induce a fixed cost of the operation. 

There are costs associated with long leases. Over the next 30 to 50 years there may be 

significant changes in the electricity industry in the U.S. due to climate change, changing 

environmental regulations, and depletion of oil and natural gas. The effects of these changes are 

difficult to predict, but it is plausible that the profitability of renewable energy generation could 

increase dramatically in the coming decades. If this were to occur, then private companies could 

be making very large profits from the use of public lands and may be paying only very low rental 

fees or royalties to the federal government due to the lease conditions that were determined when 

the economics of offshore wind farms were very different. Even leases in which royalties are 

based on gross revenue may have this problem. In this case, even though the government’s 

roylaties would increase as the profit of the developer increased, the public may demand a higher 

proportion of revenue from a highly profitable enterprise than they would from a barely 

profitable enterprise. 

Long leases also do not allow for repowering. If a company repowers a wind farm it might have 

to shutdown turbines, which would induce a minimum royalty payment to the landowner. It is 

also likely that repowering would be expensive. For example, if a lease was for 30 years and 

repowering would be expected to occur after 20 years, then a company may decide that it would 

not be able to recoup the costs of repowering over the remaining 10 years of the lease. 

Long leases will raise surety bonding requirements. In general, surety bonds are short term 

instruments which require the insurer to estimate the financial viability of a company over 2 to 5 

years. In the oil and gas industry, surety bonds can be longer which increases the risk to insurers 

and the insurance premium and decreases the number of companies capable of insuring these 

projects. In the offshore wind industry, it would be very difficult for underwriters to project the 

financial viability of a company over a period of 3 to 5 decades; as a result, we would expect 

collateral requirements to be very high. 

Clauses which allow for the renegotiation of specific terms under specific circumstances may 

help to deal with some of these issues. For example, regulators could insert clauses into leases 
109

that allow for renegotiation of royalty rates if the price of a kWh (and associated renewable 

energy credits) exceeds some threshold (perhaps 25 cents, adjusted for inflation). Similarly, 

regulators could allow for renegotiation if the developer could demonstrate that by repowering 

the site they could increase electrical output by some percentage. 

Lease Fees

Low lease fees that encourage development have been supported in the U.S. by both industry and 

environmental groups (Coequyt, 2006; Cousins, 2006; Evans, 2006; Heimann, 2006; Hobson, 

2006; Kennedy and Chasis, 2006; Pope, 2006; Quaranta, 2006). In Europe, lease fees are either 

non-existent, or overwhelmed by government subsidies. In Texas, royalties are more significant, 

up to 5.5 percent of gross revenue. 

Lease fees include royalties and rental fees. Generally, royalties are used when one party owns 

something and allows another party to profit from its use. For example, in the oil and gas 

industry, the federal government owns the oil and allows a private company to extract it, with a 

royalty paid to the federal government. In the case of offshore wind, royalties may not be 

appropriate since the federal government does not own the wind. Instead, the public owns the 

land that wind turbines would use, thus, rental fees may be more appropriate. 

However, in structuring a lease agreement it may be preferable to use royalties over rental fees. 

The use of low rental fees and higher royalty rates could allow for companies to pay lower 

upfront costs during resource assessment and construction phases and then to pay higher costs 

once the project begins generating power, and thus, revenue. Royalties may also ensure that the 

public benefits from the use of a public resource. If the value of renewably generated electricity 

increases, land rents would not capture this increase but a royalty on gross revenue could. 

In deciding the proper rate for lease fees, regulators must decide what these lease fees are 

designed to collect. Should they collect the administrative costs, the opportunity costs or forgone 

competing uses, or the maximum public monetary benefit? If they are designed to cover only 

administrative costs then the leasing fees could be quite low. Similarly, since offshore wind 

projects should not exclude most other uses of the area (i.e. commercial fishing, recreational 

fishing and boating, other alternative energy uses), the opportunity costs might also be low 

(Cousins, 2006). The primary opportunity costs lost would be from sand and gravel mining and 

trawling, which may or may not occur on the site. Conversely, if fees are designed to collect the 

maximum monetary benefit the fees would be limited only by the competitive process and the 

profitability of the projects. 

Lease fees may or may not be balanced against already existing tax credits and other subsidies 

for renewable energy. The federal Production Tax Credit (PTC) gives producers of renewably 

generated electricity a tax credit of 2 ¢/kWh over the first 10 years of generation. For 

comparison, the BLM charges about 0.09 ¢/kWh. Similarly almost all of the states that may 

eventually produce offshore wind energy (the exceptions being Louisiana, Virginia, Georgia, and 

Michigan) have Renewable Portfolio Standards which create a market for renewable energy 

certificates. It would seem to make little sense for the government to financially encourage wind 

energy with tax credits and renewable energy mandates, while at the same time collecting large 
110

rental fees. However, the BOEMRE has argued that these financial incentives are designed by 

Congress to represent the value of the societal benefit from renewable energy production 

(Federal Register, 2008a). By this logic, regulators need not concern themselves with the 

societal benefit of offshore wind power and only need to consider the fair return to the public for 

the use of public land. 

Finally, it is important to note that at this stage of development, lease fees can stymie 

development, but they cannot truly stimulate it. A high fee (5 percent) of gross income could 

potentially hinder development, but the converse is not equally true. Even if lease fees are so 

small as to be negligible, it is the underlying economics of offshore wind farms that will 

determine if they are built. Of course, low lease fees will cause developments to be more 

profitable and allow for development in areas that higher lease fees might foreclose, but only a 

subsidy of several cents per kWh would change the underlying economics of offshore wind 

farms and truly stimulate the industry. 

Timelines for Development

Low lease fees could also retard development. If lease fees or rental rates are low enough that a 

company could cheaply secure rights to an area and thereby exclude competitors, then companies 

may attempt to rent large portions of land without the intent of ever developing them. Winergy 

has been accused of this (Kaplan, 2004). As a result, most leases have inserted timelines for 

development with developers having a specified amount of time (usually 3 to 5 years) to begin 

construction and operation. 

Strict timelines could force a developer to begin construction when market conditions are not 

favorable. The cost of construction and turbines are the largest costs facing offshore wind 

development. These costs are dependent on steel prices and vessel rates which can be volatile. 

Thus, strict timelines might force a developer to begin construction at a time when the costs of 

construction are temporarily high, endangering the financial viability of the project. 

Phased Access

Leases usually grant some type of phased access in which the lessee has a short term right to 

evaluate a wind resource with the option for a longer term right to develop that wind resource. 

Phased access allows developers to reliably estimate the wind resource at a site, thereby 

estimating cash flow and removing a degree of uncertainty from their development decision. 

Phased access is widely supported by developers (AWEA, 2006; Cousins, 2006; Hobson, 2006; 

Quaranta, 2006). Phased access that does not include a preferential right for the developer doing 

the resource assessment to exploit the resource may stymie development. Resource assessments 

may be expensive and a company may be unlikely to enter into a lease allowing them access to 

an area for resource assessments if they are not granted the right to develop the resource. The 

only system in which there is no real phased access is in Denmark, where the government selects 

sites and conducts preliminary studies that essentially mirror the early phases of developer access 

elsewhere. 
111

Regulators must also decide if they should allow leases for pilot projects that might follow 

different rules than large scale projects. For example, regulators could allow projects below a 

specific capacity to be processed on an expedited basis using less stringent environmental review 

(Firestone et al., 2004). 

Project Criteria

When conducting a competitive lease, the government can either specify the generating capacity 

of the planned development (as in Texas and Denmark) or they could allow developers to submit 

their own plans for the land to be leased. Allowing developers to decide the capacity of the 

proposed projects could give large developers an advantage over smaller developers. For 

example, a large developer may be able to reasonably propose a 300 MW development on a 

given area while a smaller developer or municipality may only be able to raise the capital for a 

150 MW development. The larger development would provide more revenue to the government, 

and would be favored in any approval system based on wholly or partially on the financial 

benefit to the public. BOEMRE has proposed to address this issue by comparing plans based on 

their per MW or per acre benefit to the government. 

9.5.2. Competition and Approval Criteria 

Competition

 

There are two main models for awarding leases. Regulators could either select sites (often with 

developer input) and hold a competitive process, or they could allow developers to select sites. 

If developers select sites, competition could be enhanced if they were presented with deadlines 

and regulations for the minimum distance to other wind farms, as in the UK. Deadlines would 

keep developers from rushing to be the first to submit a proposal rather than the best (as in 

Germany), while minimum distance requirements (for example 10 km) would help to define 

when two proposals were actually competing. 

If regulators select sites, competition could be simplified if they also set guidelines for 

development, especially the size of development, as in Denmark. This would make comparisons 

of alternative projects simpler; however, if the guidelines were too detailed, it might also restrict 

creativity. Regulators selecting sites would also ensure that development occurred at a measured 

pace, much as it has in Denmark. 

If a regulator decides to select sites, it may take several additional years for offshore wind 

projects to commence while the regulator conducts detailed studies. One option would be to 

follow the British example and to conduct leasing in two phases. The first phase would be 

developer driven in which developers would have to submit proposals for specific sites by a 

specific date. While this first phase was ongoing, regulators could identify potential suitable 

areas, begin the environmental review process and conduct a leasing competition similar to those 

it conducts for oil and gas leasing. In the long term, by beginning the environmental review 

process before competition, regulators might speed development. 
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Approval Criteria

The degree of competition will in part decide the criteria by which proposals will be judged. If 

there is no competition then proposals may be judged on technical and economic feasibility, 

profitability and environmental impacts. If there is competition, then an additional criteria of 

compensation to the government may be added. 

The use of profitability as an approval criteria has costs and benefits (Heimann, 2006; Pope, 

2006). Its use would lower the possibility that developers would go bankrupt and therefore be 

unable to remove wind turbines and foundations, an important consideration for regulators. 

However, industry groups have argued that it would be difficult for regulators to accurately 

predict the economic return of an offshore wind project to a company and that private companies 

already have oversight of their financial decisions from investors and shareholders (AWEA, 

2006; Cousins, 2006; Hobson, 2006; Quaranta, 2006). 

The use of a profitability standard may retard development in the short term but might encourage 

development in the long term. Determining the profitability of a proposal would likely take a 

significant amount of time and resources; however, if regulators intend to establish a successful 

long-term leasing program, ensuring that the programs that are built remain profitable and 

operational is important. 

9.5.3. Environmental Analyses 

 

The National Environmental Policy Act (NEPA) requires that the federal government consider 

the environmental impacts of all of its decisions. Similar laws apply in Europe. The most 

complete form of environmental analysis under NEPA is the EIS, a document which can take 

years to complete. Alternatively, NEPA allows for shorter EAs if significant environmental 

effects are unlikely, or CXs if actions do not have significant environmental affects. BOEMRE 

could require site specific EISs for every offshore wind power development, as favored by 

environmental organizations (Coequyt, 2006; Pope, 2006). This may be appropriate given the 

scope and nature of offshore wind energy (Kellerman et al., 2006; Öhman et al., 2007). 

Alternatively, BOEMRE could conduct a programmatic EIS for offshore wind power (it has 

already conducted a PEIS for alternative energy use in general) (USDOI, MMS, 2008c) and use 

EAs and CXs, as favored by some representatives of industry (Hobson, 2006). Site specific EISs 

will slow development compared to CXs and EAs, but will ensure NEPA compliance and will 

ensure that the environmental impacts of a specific project at a specific site are considered. 

Given that there has been local opposition to proposed wind farm development in the U.S. (i.e. 

Citizens to Protect Nantucket Sound), it seems plausible that a BOEMRE decision to issue a CX 

could be challenged in court (Brown and Escobar, 2007). Also, the environmental impacts of an 

offshore wind farm are likely to be site specific. A final compromise option would be for 

BOEMRE to develop a PEIS for offshore wind and allow site specific EISs to branch off of the 

PEIS. 

If regulators require site specific EIS (or their equivalent) for all offshore wind projects, there is 

an additional decision regarding the amount of data to require. Regulators could issue blanket 

guidelines for data or could allow data requirements to be developed for each EIS. Blanket data 
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requirements will likely slow development unless they are so minimal as to be largely 

meaningless. The US Fish and Wildlife Service has argued that three years of avian radar data 

be collected for each EIS (Bennett, 2006). 

9.5.4. Operational Issues 

Regulators must decide how to monitor the operation of offshore wind farms including 

environmental compliance and worker safety. Regulators must first decide who should conduct 

the required monitoring. The government, developers, or a third party could conduct the 

required monitoring. There is a clear conflict of interest if developers are allowed to conduct 

their own compliance monitoring, but this is likely to be the cheapest option and it is favored by 

developers (AWEA, 2006; Cousins, 2006; Hobson, 2006; Quaranta, 2006). Third party 

monitoring is likely to be more expensive, and government monitoring would require regulators 

to develop new institutional skills. 

The methods for conducting environmental monitoring are also important. Adaptive 

management, in which a project is monitored for its environmental impact and project 

parameters are changed as issues are identified, is a widely used method for natural resources 

management (Holling, 1978). However, adaptive management requires both reliable data, and 

an ability to adjust operating parameters if an issue is detected. In the offshore wind farm 

environment it can be difficult to monitor environmental effects. Wind farms are spread over 

tens of square miles and dead animals will often disappear into the sea. Full-time onsite 

personnel, while expensive, may be required if adaptive management is to be successful. To 

date, none of the offshore wind farm installations are manned, but Horns Rev II is expected to be 

the first manned offshore wind farm. Furthermore, if an unforeseen problem arises it is not clear 

what mitigation measures could be taken. These mitigation measures would need to be explicitly 

identified in the lease. The alternative to adaptive management, a regulatory scheme in which all 

research is done prior to construction and all of the relevant issues are identified and optimal 

policies chosen before operation, may not be plausible in the case of offshore wind farms due to 

the fact that offshore wind farms are so novel and so much remains unknown about their 

operation and interaction with the environment. 

Worker safety is vitally important for offshore wind farms, but has not been seriously addressed 

by regulators. Since the wind industry began in the 1970’s at least 33 people have been killed 

installing and servicing wind turbines (Gipe, 2007). Most of these deaths have been caused by 

either falls, entanglement in the internal machinery of the nacelle, or vehicle accidents during 

transport. These deaths have resulted from worker error and equipment malfunctions. The 

offshore wind industry will share all of the dangers of the onshore industry and will have 

additional hazards. Like the onshore industry, maintenance on offshore turbines will require 

workers to regularly climb to the nacelles of turbines, several hundred feet above the surface. 

However, the offshore industry raises the additional hazard of gaining access to the turbine. 

Access can be through either boats or helicopters. Moving personnel and equipment from boats 

onto a boat landing on turbine tower could be hazardous, even in moderate seas. As a result, 

there is interest in developing stable catamarans with specially designed bows to facilitate safe 

movement. In the offshore oil industry a great deal of personnel movement is carried out by 
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helicopter; however, in the offshore wind industry this involves helicopters hovering nearby 

turbine blades which is dangerous, although this is done in limited circumstances. 

Power purchase agreements (PPAs) are another important consideration for regulators. PPAs are 

contracts between an electricity producer and the utility that operates the grid and provide a 

stable price for both parties over a long term. Without a PPA, a wind farm would have to sell its 

electricity on the spot market. Currently, offshore wind leases do not contain clauses forcing 

developers to obtain PPAs, although they could potentially reduce the risk of bankruptcy. 

9.5.5. Decommissioning 

Regulators have given minimal attention to decommissioning. In the BOEMRE Cape Wind 

Draft EIS, a 718 page document, just a page and a half was dedicated to decommissioning. 

Likewise, the UK did not develop decommissioning guidelines until years after their first 

offshore wind farms were operational. 

Bonding Methods

There are a number of options for ensuring decommissioning. Surety bonds, letters of credit and 

escrow accounts could all be used to ensure that the funds required for decommissioning are 

available at the end of the lease or if the company goes bankrupt (Kaiser and Pulsipher, 2008). 

An irrevocable letter of credit and a surety bond ensure that funds are available regardless of the 

financial standing of the developer. Depending on the terms of the escrow account, it may or 

may not ensure that the necessary funds are available throughout the lease since some escrow 

accounts do not require the full amount needed for decommissioning be deposited until several 

years after the start of operations. 

Studies of alternative methods of decommissioning compliance in the oil and natural gas 

industry have indicated that surety bonds afford regulators with a high degree of certainty that 

the site will be decommissioned according to agency requirements, and do so with relatively low 

costs to either the government or the developer (Ferreira et al., 2004; Ferreira and Suslick, 2001). 

Not surprisingly, almost all bonds in the offshore oil and gas industry are surety bonds; it is 

reasonable to expect that most offshore wind structures will be bonded with surety bonds. 

Decommissioning Options

In the oil and gas industry every structure must eventually be removed. However in the offshore 

wind industry the wind resource is inexhaustible, so decommissioning will only need to occur in 

the case of bankruptcy, unprofitability, or if there are no repowering options available. At the 

end of a lease the lessee may have one of several desires. The lessee may want to repower the 

site, the lessee may want to keep the site in production, but not repower it (perhaps in order to 

forestall paying decommissioning costs), or the lessee may want to abandon the site. Regulators, 

in turn, have several options. If the lessee wants to repower the facility or otherwise keep it in 

production, they could either renegotiate or terminate the lease. If the lessee chooses to 

terminate the lease, regulators could either force the lessee to decommission the site or they 

could allow for an agreement in which a new third party takes over the lease site. Presumably, 
115

the new third party would inherit ownership of the turbine structures and transmission facilities 

and the liability for their removal. Under current oil and gas law, the previous owner is still 

liable for decommissioning if the new owner declares bankruptcy. 

In the case of bankruptcy, the liability for structure removal could eventually fall to the 

government (depending on if the site transfers ownership or is inherited by creditors). If the 

government becomes responsible for the site, it could either decommission the site using a surety 

bond, or it could auction off the rights to operate the site. 

Regulators must also decide whether or not to allow the use of offshore wind foundations as 

artificial reefs. Monopiles and gravity foundations lack the structural complexity of jacketed 

foundations and may be less productive as artificial reefs, but studies at two wind farms in 

Sweden have shown greater diversity of fish and greater numbers of blue mussels were found 

near monopile foundations than in control sites (Wilhelmsson et al., 2006). 

Decommissioning Costs

If the government decides to decommission the site, it must ensure that the size of the bond 

covers removal costs. Importantly, there are no published studies on the appropriate value of 

these bonds for offshore wind facilities and there are reasons why bond values from the offshore 

oil industry may not be appropriate for the wind industry. First, anywhere from 25 to 50 percent 

of the costs of decommissioning oil and gas structures stem from the costs of plugging and 

abandoning wells which will not occur in offshore wind decommissioning (Kaiser et al., 2003). 

Secondly, oil platforms are usually 4 or 8 piled structures, whereas wind foundations are usually 

single piled, similar to caisons, although foundations in deeper water may have 3 or 4 piles. 

Offshore wind farms are also not likely to be in water as deep as oil and gas platforms for the 

next decade or so. 

Studies of decommissioning costs of oil and gas structures in the Gulf of Mexico suggest that the 

average cost for removing a 4 piled structure, discounting plugging and abandonment and 

pipeline abandonment operations, is $664,000. These data were from structures decommissioned 

between 1991 and 2001; adjusting for inflation and assuming a normal distribution of costs and 

years, the cost in 2008 would be $926,000. The cost for an 8 piled structure is approximately 1.5 

times that of a 4 piled structure, thus, it would not be appropriate to assume that a 1-piled 

structure would cost one-fourth of a 4-piled structure. Instead, a 1-piled structure might cost 33 

to 50 percent of a four piled structure or $305,000 to $463,000. A wind farm might be composed 

of 100 or more turbines, but due to economies of scale, it is unlikely that the decommissioning 

costs will scale linearly. Thus, a 100 turbine wind farm should cost less than $50 million to 

decommission. 

 

Importantly, $50 to $60 million in liabilities is the maximum amount that the U.S. offshore oil 

and gas plugging and abandonment surety bond market can underwrite. One of the two major 

companies in this industry, RLI, has expressed some interest in the offshore wind market and 

may be willing to underwrite some projects. However, the surety bond market is extremely risk 

averse and they may require large amounts of collateral before issuing a bond. 
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9.6. Conclusion 

A number of commentators have concluded that the preferred way for nations to regulate the 

offshore wind industry is to set up a “one-stop shop” (as in Denmark) approach in which 

permitting authority is consolidated into a single governmental agency (Firestone et al., 2004; 

Peloso, 2006; EWEA, 2007). In our review, we found no evidence that a one-stop shop would in 

fact speed development. Given the large amounts of time, capital and planning involved with the 

development of an offshore wind farm, it seems unlikely that the requirement to seek permits 

from numerous governmental agencies is a significant administrative burden on applicants. Both 

the BOEMRE oil and gas leasing program and the UK offshore wind programs have been 

successful despite requiring permitting and consultation from a variety of government agencies. 

Instead, we find few relationships between regulatory techniques and successful installations. 

We do note the lack of development in Germany, and to a lesser extent the Netherlands, and 

question whether that is associated with a regulatory system that rewards first, rather than best, 

applicants. While over-regulation, especially through high fees, may be able to handicap the 

offshore wind industry, regulators are unlikely to be able to actually stimulate the offshore wind 

industry. The industry will experience rapid growth only when technological development, cost 

reductions from learning and government subsidies allow it to compete in the market. 

As important or more important for the development of offshore wind power are the subsidies 

that federal and state governments authorize for renewable energy in general and offshore wind 

power more specifically (Bird et al., 2005; Reiche and Bechberger, 2004). It would be easy to 

ascribe the success of Denmark and the UK to convenient regulations, but it is far more likely 

that a mix of financial subsidies and amenable offshore sites has led to the development of the 

offshore wind industry in these countries. 

 
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10. COMMENTARY ON THE USE OF OFFSHORE OIL AND GAS 

INFRASTRUCTURE IN WIND ENERGY APPLICATIONS 

Platform removal represents a liability for the oil and gas industry and there has been interest in 

alternative options to removal for many years. One recently discussed alternative is to place 

wind turbines on oil and gas structures after production ceases either for wind farm development 

or for enhanced oil recovery. In this final chapter, we discuss the benefits of these plans, the 

difficulties with their implementation and the alternative possibilities for synergy between the 

offshore oil and gas and wind industries. 

10.1. Introduction 

There are two options for the use of oil and gas infrastructure in the offshore wind industry. The 

first option is to place wind turbines on platforms without removing the platform from its current 

location. The second option is to remove platforms from their current location and to reuse them 

as foundations for wind turbines. There are costs and benefits associated with both of these 

options; however, neither option is particularly attractive or likely to provide a market for many 

offshore structures. 

At least two companies, WEST and Talisman Energy, have investigated the potential for using 

oil and gas infrastructure in the offshore wind industry. Talisman Energy has been actively 

investigating the possibilities of using the infrastructure of the Beatrice oil platform for offshore 

wind power. In 2006 and 2007, Talisman installed 2, 5 MW turbines in 45 m of water 1.6 and 

2.3 km away from their Beatrice platform in the Scottish North Sea. The turbines were placed 

on jacketed foundations, and anchored to the seafloor with piles. The two turbines are linked to 

each other and the main platform with a 33 kV underwater electrical cable and can supply about 

33 percent of the platform’s electrical consumption (Eaton, 2008). The platform is also 

connected to the Scottish grid. Talisman developed this site as a 5 year test facility for a much 

larger, 1 GW development which would utilize the current Beatrice infrastructure for electrical 

service platforms, crew quarters and electrical transmission. 

 

Talisman estimated the energy costs at Beatrice to be about $15 million in 2006. The Beatrice 

project cost $90 million (Eaton, 2008). Whether the wind turbines pay for themselves through 

reduced fuel costs will depend primarily on the future price of energy and the discount rate used 

to finance the project. 

In the U.S., the Louisiana-based Wind Energy Systems Technology has also been investigating 

the potential use of oil and gas structures for offshore wind farms. They are in the late planning 

stages for an offshore wind farm off the coast of Galveston, Texas and have spent several years 

considering how to efficiently take advantage of the infrastructural resources of the GOM 

(Schellstede, 2008). They have decided that the GOM has a number of infrastructural 

advantages that make it appropriate for the development of offshore wind energy; however, these 

advantages are mostly associated with the skills and experiences of the people working in the 

offshore oil and gas industry rather than the physical infrastructure in the GOM. 

 

 
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10.2. Benefits 

The use of offshore oil structures as wind foundations has benefits for both the oil operator and 

the wind developer. For the oil operator, the benefit would be the ability to sell a structure for 

more than the scrap value and avoiding or deferring decommissioning costs. For the wind farm 

developer, the primary benefits are through reducing foundation costs and reduced 

environmental impacts. 

 

10.2.1. Delaying Decommissioning Costs 

For the oil industry, one of the biggest benefits of placing wind turbines on oil and gas structures 

is the ability to defer decommissioning costs. Since present costs are discounted relative to 

future costs, this would save oil operators money. Of course, this would only be possible if the 

structures were not going to be moved to another location. Decommissioning costs are highly 

variable and are a function of the size of the structure and its depth. On average, removal costs 

for a single-piled caisson structure in under 100 ft of water is $500,000. For a fixed platform, the 

cost is $875,000 (Kaiser et al., 2003). Thus, by converting an oil and gas structure to wind use, 

an offshore operator may be able to defer over $500,000 in costs, or pass these costs along to a 

new owner.26 

 

10.2.2. Foundation Costs 

 

For wind power developers, decreasing the costs of foundations is a major benefit of using 

platform foundations for wind turbines. Foundation costs are a large proportion of the total costs 

of offshore wind power. Foundations, including installation, are estimated to represent about 20 

percent of the capital costs of offshore wind farms (Morgan et al., 2003; ODE, 2007) and 10 to 

20 percent of the cost of energy (Musial et al., 2006; Dept. for Business Enterprise and 

Regulatory Reform, 2004). In general a used foundation in the GOM will sell for about 30 to 50 

percent of its original fabrication costs (Byrd, 1998). Thus, by using a previously constructed 

foundation over a new foundation, developers may be able to save 10 percent on total capital 

costs. These costs assume that the foundation is brought to shore; if the wind operator were to 

use a foundation in place, the cost savings could be greater. 

10.2.3. Marine Habitat 

Offshore oil and gas structures serve as artificial reefs and provide habitat for marine organisms 

(Kasprazk, 1998). The removal of these structures removes this habitat. In some cases, offshore 

oil and gas platforms are toppled in place or moved to nearby locations to serve as artificial 

reefs; however, the removal of these platforms has environmental impacts, which could be 

delayed by using platforms as foundations for wind turbines. Furthermore, by placing a wind 

turbine on a structure already in the GOM, the environmental impacts of wind farm could be 

reduced since piling operations would not be needed. 

 

26 Importantly, decommissioning obligations can never be entirely avoided. Even if a structure is passed to a new 

owner, the government can seek to recover decommissioning costs from the original owner if the new owner is 

unable to pay these costs (Federal Register, 2008a). 
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10.2.4. Visual Benefits 

One of the primary objections to offshore wind power has been that it presents a visual disamenity to nearby landowners. However, it is likely that offshore wind turbines would present a 

visual amenity when compared to offshore oil and gas platforms. In the U.S., oil and gas 

platforms can be seen from the coasts of several Gulf States, including some beaches used for 

vacation and recreation, for example, Gulf Shores, Alabama. If residents and visitors viewed 

offshore wind turbines more favorably than offshore oil and gas structures, then the replacement 

of oil platforms with wind turbines could act as a visual amenity and could potentially lead to an 

increase in tourism. 

 

10.3. Difficulties 

10.3.1. Economies of Scale 

One of the biggest difficulties in using oil platforms for wind energy is in the economies of scale. 

The cost per kWh of offshore wind energy decreases with increasing sizes of development 

(Barthalemie and Pryor, 2001). In part, this is due to lower prices for large turbine orders; for 

orders of hundreds of turbines, the actual price can be up to 55 percent below the list price 

(Junginger et al., 2005). Therefore, developments need to be composed of dozens or hundreds of 

identical wind turbines. Offshore wind developers intending to use foundations from the 

offshore oil and gas industry would need to find dozens of similar foundations. Since 

foundations in the oil and gas industry are custom made for a specific purpose and site, and since 

platforms are decommissioned and either reused or sold as scrap as they reach the end of their 

economically useful life, this could be difficult. 

10.3.2. Location 

While the GOM does have some sites that may be amenable to offshore wind power, in general 

the winds off Texas, Louisiana, Mississippi and Alabama are not as powerful as those in other 

parts of the country, especially the northeast (Archer and Jacobsen, 2005; USDOE, NREL, 

2008). Similarly, electricity rates in the southern U.S. and renewable energy policies in these 

states are not amenable for new and expensive renewable energy development. Of the GOM 

states, only Texas has a Renewable Portfolio Standard (DSIRE, 2008), and only Texas has an 

average retail electricity price of over 10 cents per kWh (USDOE, EIA, 2008). Thus, the GOM 

in general is not at present a particularly attractive market for offshore wind energy. 

The location of platforms within the GOM is important. The amount of wind energy available to 

a turbine scales with the square of wind speed. As a result, wind turbines need to be placed in 

high wind areas in order to generate as much electricity as possible. Thus, it is not likely that the 

placement of oil and gas platforms will be suitable for wind turbines; and while there are areas of 

the GOM that may be appropriate for wind use, most areas need further resource assessment. 

 

Additionally, turbines need to transmit generated electricity to shore; this becomes more difficult 

and expensive as the distance to shore increases. Consequently, most offshore wind farms have 

been located less than 10 miles from shore and offshore oil and gas foundations far from shore 
120

would not be useful for wind energy generation. As a result of these constraints, it would be 

difficult for developers to use offshore oil and gas infrastructure for wind energy applications 

without removing the platforms and transporting them to a new location. 

10.3.3. Configuration 

Wind turbines need to be precisely positioned within the wind farm. Wind turbines need to be 

separated from each other, usually by 500 to 1,000 m, in a grid arrangement to reduce wake 

effects and to minimize cabling layout. Existing oil and gas infrastructure is not suited to this 

requirement. Thus, the only real option available to wind developers seeking to use the oil and 

gas infrastructure of the GOM would be to collect dozens of similar jacketed foundations and to 

move them to a new site. It is unlikely that a developer would be able to find these foundations 

as operating structures and be able to wait for them to be decommissioned; instead, a developer 

would have to collect and store these foundations among previously decommissioned structures. 

This has proven impractical for WEST (Schellstede, 2008). 

 

10.3.4. Engineering Requirements 

 

In most cases the 4-piled oil and gas foundations are not the most efficient foundation for an 

offshore wind turbine in shallow water. In the shallow waters of the North Sea, monopiles and 

gravity foundations have been used much more frequently than jacketed foundations. Jacketed 

foundations generally require four piles to be driven per foundation, while monopiles require 

only one pile driving operation per turbine and gravity foundations do not require pile driving. 

These additional piling operations would add economic and ecological costs to an offshore wind 

farm which would have to be balanced by the saved costs of the recycled foundations. 

 

It is also important to note that not all offshore oil and gas structures are amenable to the 

placement of offshore wind turbines. Offshore oil and gas structures are designed to handle 

significant vertical weights; however, they are not designed to handle the kinds of horizontal 

forces that an offshore wind turbine is subject to. The foundations for offshore wind turbines 

must be engineered to withstand powerful winds acting on three-60 m long blades and a 100 m 

high steel tubular pole. While many oil and gas structures may be able to handle these forces, 

their ability to do so must be analyzed on a case-by-case basis. 

Additionally, some oil and gas structures in the GOM are over 60 years old and many more are 

40 to 50 years old. While oil and gas structures are generally designed for 100 year lifetimes, a 

platform built decades ago would require significant inspection and upgrade before it could be 

used as a foundation for a wind turbine. 

 

10.4. Alternative Offshore Uses 

10.4.1. Intra-Field Use 

Another possibility is to use unused oil and gas platforms as foundations for wind turbines and to 

transfer the electricity to other nearby oil and gas platforms. This has a number of potential 

advantages but has not been well studied. First, it would allow for wind turbines to be placed far 
121

offshore, where wind speeds are generally higher, but would reduce the need for long distance 

transmission. This would eliminate the need for high-voltage transmission and thus offshore 

electrical service platforms. Second, it would allow wind power to compete not with coal fired 

electricity, but with the diesel fuel or natural gas that normally powers offshore oil and gas 

platforms. Finally, it might provide enough cheap electricity to make enhanced oil recovery 

economically feasible in the GOM. 

Since wind is not constant, wind energy could not replace diesel or natural gas fired electricity 

on offshore platforms, but could only supplement it. Thus, offshore platforms would still need 

generators and associated infrastructure and the only savings would be in a reduced consumption 

of fuel. 

The feasibility of using existing oil and gas structures for electricity generation for nearby oil and 

gas platforms will depend on a variety of factors. In general, diesel powered platforms far from 

shore will be more amenable to offshore wind usage than natural gas powered platforms and 

those close to shore. This is because as distance to shore increases the transport costs of fuel and 

the wind speed increase, making wind power more profitable. Wind turbines require large upfront costs which take years of profitable operation to recover. Thus, only structures and leases 

with at least 15 to 20 years of future life could be expected to be economically converted to wind 

usage. Again, these structures are most likely to be the newest structures in the deep water 

furthest from shore. However, the structures far from shore in deep water are at lower densities 

than those closer to shore; thus it is unlikely that there will be a nearby inactive structure to act as 

a foundation. 

10.4.2. Small Scale Use 

Despite the problems of economies of scale, there have been and continue to be small 

community based projects of a few offshore turbines generating electricity for a locally owned 

cooperative. Examples are in Samso, Denmark and Hull, Massachusetts (Manwell, 2007). Thus, 

it is reasonable to think that a community could purchase or lease a small number of nearby oil 

and gas platforms and place wind turbines on them. However, the oil and gas platforms located 

close to shore in the GOM are primarily off coastal Louisiana, an area with small population 

densities and covered by swamps and other environmentally sensitive areas. It is reasonable to 

think that the costs, both economic and ecological, of laying transmission cables in this area 

would be significant. Furthermore, these areas have low population densities and high levels of 

poverty and it is unlikely that these communities would be as willing or able to finance offshore 

wind power projects as those in Massachusetts or Denmark. 

10.4.3. Electrical Service Platforms 

Oil and gas platforms could be relatively easily used as foundations for electrical service 

platforms (ESP) for offshore wind farms. ESPs are present at almost all offshore wind farms and 

are used to increase the voltage from approximately 33 kV among the inter-turbine electrical grid 

to over 100 kV for transport to shore (Ackermann, 2005). From an engineering standpoint, ESPs 

are similar to oil and gas platforms in that they are heavy and compact and subject to lower 

horizontal loads than wind turbines. WEST is planning on using a recycled jacketed platform for 
122

this purpose (Schellstede, 2008). As wind farms grow in size and reach further offshore, DC 

transmission will become more attractive. DC transmission requires a significant amount of 

space for conversion from AC to DC, thus, large jacketed structures used in the oil and gas 

industry may become increasingly useful for offshore wind farms. 

10.4.4. Electrically Connected Platforms 

 

In the GOM, offshore platforms are powered by diesel fuel or natural gas and are not connected 

to the onshore electrical grid. In Europe, however, some offshore production facilities are linked 

by electrical transmission cables to the mainland. Offshore wind farms could use this existing 

infrastructure. In this case, a developer could conceivably have to pay neither transmission nor 

foundation costs; this would total a 30 to 35 percent reduction in capital costs. 

 

10.4.5. Resource Evaluation or Technology Testing 

Resource evaluation, including the long term measurement of wind speeds at the hub height of 

proposed turbines is an important component of planning and developing an offshore wind farm. 

Existing offshore oil platforms may be well suited to this task, and indeed several structures in 

the GOM collect a wide variety of wind related data (Kaiser and Pulsipher, 2007b). In this case, 

large numbers of foundations are not needed, the platforms do not need to be electrically 

connected to the mainland, and the engineering requirements for placing 60 m high anemometer 

masts are not as significant as the requirements for placing an entire turbine at an equivalent 

height. Thus, it is plausible that oil and gas foundations could serve as platforms for resource 

evaluation. Similarly, technology testing is expected to become an important part of the future 

ocean energy industry. Wind energy developers may seek to test new turbine concepts, or 

current or wave energy developers may seek to test new energy conversion technologies. Again, 

oil and gas structures may provide a convenient platform for these activities. 

10.5. Factors Influencing Utilization 

There are a number of factors that make reusing oil and gas infrastructure for offshore wind 

power impractical; however, changes in some of these factors may make it more likely that wind 

developers would seek to use GOM infrastructure for offshore wind projects. If the costs of 

wind turbines decreases and the value of renewable energy increases, perhaps due to greenhouse 

gas legislation, then it is possible that developers could ignore issues of scale and could place 

wind turbines on the small number of available appropriate structures. It seems likely that the 

value of renewable energy will increase due to legislation; however, the cost of wind turbines has 

also been rising in recent years due to climbing demand. 

If the offshore wind industry develops to a point in which shallow sites have already been 

developed, or are found to be ineligible for development for environmental or aesthetic reasons, 

then developers may be drawn to deeper waters. The jacketed structures used in the oil and gas 

industry are well suited to these waters while the traditional foundation techniques used in the oil 

and gas industry, monopiles and gravity foundations, are not. This might make the re-use of oil 

and gas infrastructure more practical since jacketed structures would not have to compete with 

gravity or monopile foundations. 
123

10.6. Conclusion 

It is possible that a few of the oil and gas platforms decommissioned in the GOM could be used 

as either ESPs in offshore wind farms or as bases for wind turbines for intra-oil field electrical 

generation or for test platforms for resource evaluation. It seems unlikely that large numbers of 

platforms will be used for these purposes. It is possible that a developer could collect a number 

of similar jacketed structures and relocate them for use in an offshore wind farm; however, this 

has so far proven impractical. If an offshore wind industry does develop in the GOM, it seems 

most likely that the decommissioned oil and gas infrastructure will serve as a source of steel. In 

sum then, the use of oil and gas infrastructure for offshore wind farms may provide a local 

market for scrap steel, but it is very unlikely that large numbers of oil and gas platforms will 

become foundations for offshore wind turbines. 
125

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151

GLOSSARY OF ABBREVIATIONS

COE-Army Corps of Engineers 

BERR-UK Department of Business, Enterprise and Regulatory Reform 

BLM-Bureau of Land Management 

BOEMRE-Bureau of Ocean Energy Management, Regulation and Enforcement 

BSH- German Federal Maritime Agency 

CE-Cost of Energy 

CX-Categorical Exclusion 

DEA-Danish Energy Authority 

DOE- U.S. Department of Energy 

DTI-UK Department of Trade and Industry 

EIS-Environmental Impact Statement 

FCR-Feed Conversion Rate 

GIS-Geographic Information System 

GLO-Texas General Land Office 

GMIT-Gulf Marine Institute of Technology 

GOM-Gulf of Mexico 

IPCC-Intergovernmental Panel on Climate Change 

LARP- Louisiana Artificial Reef Program 

LIOWP-Long Island Offshore Wind Park 

MFA-Marine and Fisheries Agency 

MMS-Minerals Management Service 

NOAA-National Ocean and Atmospheric Administration 
152

NPV-Net Present Value 

NREL-National Renewable Energy Laboratory 

OAC-Gulf of Mexico Offshore Aquaculture Consortium 

OCS-Outer Continental Shelf 

OOA-Open Ocean Aquaculture 

PTC-Production Tax Credit 

P&A-Plug and Abandon 

NEFA-National Fisheries Enhancement Act 

NEPA-National Environmental Policy Act 

REC- Renewable Energy Credit 

RHA-Rivers and Harbors Act 

ROD-Record of Decision 

ROV-Remotely Operated Vehicle 

RPI-Reef Priority Index 

RPS- Renewable Portfolio Standard 

SARS-Special Artificial Reef Site 

SEA-Strategic Environmental Assessment 

TARP-Texas Artificial Reef Program 
153

 

APPENDIX A. 

CHAPTER 1 TABLES AND FIGURES 

 
155

Table A.1.

Structurea

 Inventory in the Gulf of Mexico (2003)

Water Depth WGOM CGOM GOM 

(ft) CAIS WP FP CAIS WP FP Auxiliary

0-20 1 0 0 200 10 35 79

21-100 79 25 119 767 268 710 318

101-200 3 17 82 48 63 490 73

201-400 1 4 85 1 12 320 31

400+ 0 0 13 0 3 43 4

TOTAL 84 46 299 1,016 356 1,598 505

Source: USDOI, MMS, 2008d. 

Footnote: (a) Structures are classified as caissons (CAIS), well protectors (WP) and fixed platforms (FP) 

across the Western and Central Gulf of Mexico (WGOM, CGOM) planning areas. An auxiliary 

structure is a structure that has never produced hydrocarbons but serves in an auxiliary role, say 

as a quarters facility, flare tower, or storage platform. 

Table A.2.

Deepwater Production Facilities Installed in the Gulf of Mexico, 

Including Plans Through 2006

Structure Type Number

Fixed Platform 5

Compliant Tower 3

TLP 8

Small TLP 6

Spar 4

Truss Spar 8

Semi FPS 5

Subsea 164

Source: USDOI, MMS, 2008d.
156

0

20

40

60

80

100

120

140

160

180

200

1973197519771979198119831985198719891991199319951997199920012003

Year

Number of Structures

CAIS WP FP

 Figure A.1. Structures Removed in the Outer Continental Shelf of the Gulf of Mexico 

 (1973-2003). 

0

500

1000

1500

2000

2500

3000

1973 1977 1981 1985 1989 1993 1997 2001 2005

Year

 Number of Structures

Caissons Well Protectors Fixed Platforms

 Figure A.2. Cumulative Number of Structures Removed in the GOM (1973-2006).

Source: USDOI, MMS, 2008d. 

Source: USDOI, MMS, 2008d. 
157

 Figure A.3. Caisson Structures. 

Source: Twachtman Snyder & Byrd, Inc., 2006. 
158

 Figure A.4. Well Protector and Fixed Platform Structures. 

Source: Twachtman Snyder & Byrd, Inc., 2006. 
159

 Figure A.5. Subsea Equipment and Configuration. 

Source: Shell, 2008. 
160

 Figure A.6. Deepwater Development Strategies. 

Source: Baud et al., 2002.
161

 Figure A.7. Federal Outer Continental Shelf Leasing Program. 

Source: USDOI, MMS, 2005b. 
162

Offshore oil and 

gas facility 

decommissioning

Oil and gas 

processing 

equipment and 

piping

Deck and jacket 

structure

Onshore scraping

Move to new 

location and 

reinstall

Dispose of in 

deep water

Convert to an 

artificial reef Send to shore

Sell for scrap Refurbish and reuse Waste to landfill Recycle steel Waste to landfill Partial removal Topple in place 

 Figure A.8. Offshore Oil and Gas Facility Decommissioning Tree. 
163

 Figure A.9. Derrick Barge Arrives On-Site and Removes the Deck Module. 

Figure A.10. Explosives Technicians Prepare and Load Charges into Conductors and 

 Legs. 

Source: USDOC, NMFS, 2004.

Source: USDOC, NMFS, 2004. 
164

 Figure A.11. Aerial View of Job Site during Blast and Detonation. 

Figure A.12. Severed Piles and Conductors Loaded onto Derrick Barge. 

Source: USDOC, NMFS, 2004. 

Source: DEMEX, 2004. 
165

 

 Figure A.13. Jacket Lifted from Water. 

Source: Chevron, 2008.
166

 Figure A.14. Jacket and Deck Transported to Shore or Artificial Reef Site. 

Source: Louisiana Department of Wildlife and Fisheries, 2008. 
167

 Figure A.15. Structure Toppled-in-Place. 

Source: Louisiana Department of Wildlife and Fisheries, 2009. 
168

Figure A.16. Platform Removal Methods. (M.L.W.EL.=Mean Low Seawater Elevation). 

MUDLINE EL. (-)248'-0"

M.L.W. EL. 0'-0"

MINIMUM CLEARANCE 85'-0"

(NOT TO SCALE)

MUDLINE EL. (-)248'-0"

M.L.W. EL. 0'-0"

MINIMUM CLEARANCE 85'-0"

(NOT TO SCALE)

MUDLINE EL. (-)248'-0"

M.L.W. EL. 0'-0"

MINIMUM CLEARANCE 85'-0"

(NOT TO SCALE)

Explosives

Mechanical Cut

Mechanical Cut

EXPLOSIVE REMOVAL METHOD

FULL MECHANICAL REMOVAL METHOD

PARTIAL MECHANICAL REMOVAL METHOD

(a) 

(b) 

(c) 

Source: Texas Parks and Wildlife Department, 2008.
169

 Figure A.17. Gorilla Net Application. 

Source: B&J Martin, Inc., 2006. 
171

APPENDIX B. 

CHAPTER 2 TABLES AND FIGURES 
173

Table B.1.

Louisiana Artificial Reef Planning Areas

Number Planning Area Blocks 

1 West Cameron 586-587, 594-595, 608-609, 616-617 

2 East Cameron 254-256, 269-274; Vermillion blocks 262, 281-282 

3 Ship Shoal 204-209, 214-219, 228-233 

4 South Marsh Island I 65-67, 75-77, 80-82 

5 South Marsh Island II 130-133, 136-139, 146-149 

6 Eugene Island 346-350, 363-372; Ship Shoal blocks 320, 343-344 

7 South Timbalier 128-135, 151-154 

8 West Delta 69-76, 89-96 

9 Main Pass 144-145, 272-273, 292-306 

 Source: Louisiana Department of Wildlife and Fisheries, 2009. 

Table B.2.

Louisiana Artificial Reef Program Structure Donations (1987-2003)

 Year Structures Donation ($) 

1987 1 250,000 

1988 4 350,000 

1989 0 0 

1990 4 875,000 

1991 4 1,292,870 

1992 10 1,326,876 

1993 13 1,134,750 

1994 16 1,266,442 

1995 4 564,840 

1996 4 736,281 

1997 8 1,167,385 

1998 4 327,642 

1999 10 2,374,657 

2000 12 1,757,243 

2001 3 145,000 

2002 8 1,244,136 

2003 12 4,103,981 

TOTAL 117 20,817,102a

 Source: Louisiana Department of Wildlife and Fisheries, 2009. 

 Footnote:(a) Includes $1.9M for a barge donation.
174

Table B.3.

Louisiana Artificial Reef Program Statistics (1987-2003)

 Structure Type Variablea (Unit) Towed Not Towed

3-pile DON ($/structure) 46,667 (3)b 450,600 (1)

DON/NP ($/pile) 15,556 (9) 150,000 (3)

4-pile DON ($/structure) 97,310 (43) 246,484 (16)

DON/NP ($/pile) 24,327 (129) 61,621(64)

8-pile DON ($/structure) 150,117 (34) 212,009 (20)

DON/NP ($/pile) 18,348 (260) 24,369 (174)

 Source: Louisiana Department of Wildlife and Fisheries, 2009. 

 Footnote: (a) The donation (DON) and donation per pile (DON/NP) are aggregated according to 

structure type (3-pile, 4-pile, 8-pile) and disposition (towed, not towed). 

 (b) Numbers in parenthesis represent the number of elements in the set. 
175

Table B.4.

Operator Donation (1987-2003)

Operator Structures Donation ($) Percentage of Total 

Donation

ChevronTexaco 34 3,349,064 17.7

Kerr McGee 10 711,508 3.8

CNG 6 1,188,350 6.3

ExxonMobil 6 1,200,000 6.3

Apache 6 701,793 3.7

Forest Oil 6 3,128,500 16.5

Hunt 6 926,404 4.9

BP/Amoco 4 758,546 4.0

Pioneer 4 365,463 1.9

Conoco 3 301,130 1.6

Coastal 3 560,000 3.0

Unocal 2 592,870 3.1

Newfield 2 506,008 2.7

Oryx 2 317,340 1.7

Delmar 2 99,729 0.5

Subtotal 96 14,706,705 77.7

Other (21) 21 4,205,397 22.2

TOTAL 117 18,912,102 100.0

 Source: Louisiana Department of Wildlife and Fisheries, 2009. 
176

Table B.5.

Structures Removed and Reefed in the Central Gulf of Mexico (1987-2002)

Water Depth Structures Removed Structures Reefed P(Reef)a P(Not Towed)

(ft) WP FP WP+FP (%) (%)

0-20 12 40 0 0 0

21-100 112 352 2 0.4 0

101-200 41 151 60 31.3 25.0

201-400 4 70 43 58.1 35.2

400+ 0 1 0 0 0

TOTAL 169 614 105 13.4 31.6

 Footnote: (a) The capture probability is computed as the ratio of all structures reefed in the 

Central GOM from 1987-2002 to the total number of well protectors (WP) and 

fixed platform (FP) removed. 

Table B.6.

LARP Donation Model Results – I

Parameter DON = α0 + α1 WD + α2 DIST + α3 NP+ α4 TIP 

Not Toweda Towed All

α0 -6,746 (*) -102,238 (-3.1) 22,568 (*)

α1 1,565 (1.7) 740 (6.4) 1,020 (3.3)

α2 -5,645 (-1.2) -282 (-1.1) -200 (*)

α3 11,831 (3.4) 4,778 (*)

α 4 145,429 (2.9)

n 37 80 117

R2 0.28 0.64 0.37

Footnote: (a) Structures not towed include toppling-in-place and partial removals. 

 (*) denotes t-statistics < 1.
177

Table B.7.

LARP Donation Model Results – II 

 

DON = α0 + α1 WD + α2 DIST 

Parameter Not Towed Towed

3,4-pilea 3,4-pile 8-pile 3,4-pile 8-pile

α0 -793 (-1.1) -428,365 (-1.1) 53,433 (*) -95,486 (-3.7) 37,069 (1.1)

α1 654 (2.0) 4,409 (1.7) 816 (2.5) 902 (8.6) 222 (2.5)

α2 -26 (*) -323 (*)

n 16 17 20 46 34

R2 0.47 0.41 0.51 0.79 0.43

Footnote: (a) Excludes an “outlier” $2.5M donation from the data set

 (*) denotes t-statistics < 1. 

Table B.8.

LARP Donation Model Results – III 

 

Parameter DON/NP = α0 + α1 WD + α2 DIST + α3 TIP 

Not Towed Towed All

α0 4,835 (*) -10,485 (-2.0) 9,721 (-1.8)

α1 134 (2.4) 156 (7.0) 197 (6.3)

α2 -47 (-1.0) -43.5 (-1.5)

α3 29,119 (2.4)

n 37 80 117

R2 0.38 0.65 0.48

Footnote: (*) denotes t-statistics < 1
178

 Figure B.1. Louisiana Artificial Reef Program Designated Planning Areas.

Source: Louisiana Department of Wildlife and Fisheries, 2009. 
179

APPENDIX C. 

CHAPTER 3 TABLES AND FIGURES 
181

Table C.1.

Texas Artificial Reef Program Platform Donations (1990-2003)

Fiscal Year Donations Structures Donation Amounta ($) 

1990 1 1 35,000 

1991 5 5b 700,590 

1992 6 7 1,104,330 

1993 3 4 521,352 

1994 4 13 122,333 

1995 2 3 612,950 

1996 1 1 256,400 

1997 3 3 392,239 

1998 3 3 482,945 

1999 2 3c 395,000 

2000 3 3 645,000 

2001 5 6 1,055,919 

2002 12 12 2,088,468 

2003 7 9 1,231,959 

TOTAL 57 73 9,644,485 

 Source: Texas Parks and Wildlife Department, 2008. 

 Footnote: (a) Does not include buoy fee. 

 (b) Does not include one donated deck. 

 (c) Does not include one donated caisson. 
182

Table C.2.

Texas Artificial Reef Program Statistics (1990-2003) 

Structure Type Variable Removal Method a

 (Unit) 

TIP TOW PR All

3-pile DON/NS ($/structure) - 64,558

(7)

175,600

(2)

89,234

(9)

DON ($/donation) - 75,318

(6)

175,600

(2)

100,388

(8)

DON/NP ($/pile) - 21,519

(21)

58,533

(6)

29,745

(27)

Severance Methodb - 5E/2M

(7)

0E/2M

(2)

5E/4M

(9)

4-pile DON/NS ($/structure) 143,107

(11)

17,382c

(20)

174,178

(8)

85,006

(39)

DON($/donation) 174,909

(9)

34,765c

(10)

199,060

(7)

127,510

(26)

DON/NP ($/pile) 35,776

(44)

4,346c 

(80)

42,225

(33)

21,116

(157)

Severance Method 9E/2M

(11)

16E/4M

(20)

0E/8M

(8)

25E/14M

(39)

8-pile DON ($/structure) 227,420

(5)

143,181

(5)

244,875

(15)

221,045

(25)

DON($/donation) 227,420

(5)

143,181

(5)

282,548

(13)

240,266

(23)

DON/NP ($/pile) 28,428

(40)

18,840

(38)

31,128

 (118)

28,195

(196)

Severance Method 5E/0M

(5)

5E/0M

(5)

0E/15M

(15)

10E/15M

(25)

 Source: Texas Parks and Wildlife Department, 2008. 

 Footnote: (a) Donation amount is presented on a structure (DON/NS), donation (DON), and pile (DON/NP) 

basis. The number of elements in each category is presented in parenthesis. Note that a donation 

may include more than one structure and so the number of donations will be less than the number of 

structures in each category. 

 (b) “E” denotes explosive removal and “M” denotes mechanical removal. The number of explosive and 

severance removals are shown for each category. 

 (c) 14 of the 20 structures provided zero donation, and so the unit cost savings may not be 

representative of the towing operation. 
183

Table C.3.

Top 5 Operator Donations to TARP

Operator Structures Total Donation ($) Program Percenta(%)

El Paso 9 1,866,517 19

CNG 3 645,000 7

ChevronTexaco 5 572,150 6

Samedan 4 401,078 4

Cal Dive/Blue Dolphin Energy 10 350,000 4

 Source: Texas Parks and Wildlife Department, 2008. 

 Footnote: (a) Percentage of total program donation. 

Table C.4.

Removed and Reefed Structures in the Western Gulf of Mexico (1990-2002)

Water Depth Structure Type Structures P(Reef) a

(ft) CAIS WP FP Reefed (%)

0-20 0 0 1 0 0

21-100 60 36 50 9 11

101-200 7 5 58 41 65

201-400 0 5 23 23 82

400+ 0 0 0 0 -

TOTAL 67 46 132 73 42

 Source: Texas Parks and Wildlife Department, 2008. 

 Footnote: (a) P(Reef) is computed as the number of structures reefed during 1990-2002 

divided by the total number of well protectors (WP) and fixed platforms (FP) 

removed during this time. 
184

Table C.5.

TARP Donation Model Results – I 

Parameter DON = α0 + α1 WD + α2 DIST + α3 NP+ α4 NS 

TOW TIP PR

α0 -156,543 (-2.8) -115,634 (-1.1) -56,418 (*)

α1 893 (3.9) 1,166 (1.9) 1,089 (2.6)

α2 -193 (*)

α3 14,852 (2.8) 12,074 (1.1) 11,831 (1.5)

α 4 2,157 (*) 6,930 (*)

n 21 14 22

R2 0.86 0.69 0.67

 Footnote: t-statistics presented in (); * denotes t-statistic < 1.

Table C.6.

TARP Donation Model Results – II

Parameter DON/NP = α0 + α1 WD + α2 DIST + α3 NS 

 TOW TIP PR

α0 -23,090 (-1.8) 22,296 (1.4) 17,232 (*)

α1 218 (4.1) 141 (1.5) 152 (1.8)

α2 -83 (*)

α3 275 (*) -2,937 (-1.7) -5,860 (*)

n 21 14 22

R2 0.79 0.48 0.59

 Footnote: t-statistics presented in (); * denotes t-statistic < 1.
185

Table C.7.

TARP Donation Model Results – III 

Parameter DON = α0 + α1 WD + α2 DIST + α3 NP+ α4 NS+ α5 ST+ α6 TIP+ α7 MECH 

DON DON/NP

α0 -150,663 (-2.7) -15,997 (-1.6)

α1 1,014 (5.0) 208 (6.0)

α2 -24 (*) -102 (*) 

α3 3,169 (2.3)

α 4 4,020 (*) -1,571 (*)

α5 43,354 (*) -12,894 (-3.7)

α6 102,141 (3.4) 13,616 (2.6)

α7 40,340 (1.8) 10,557 (2.6) 

n 57 57

R2 0.84 0.82

 Footnote: t-statistics presented in (); * denotes t-statistic < 1.
186

 Figure C.1. Texas Artificial Reef Sites and High Island General Planning Area.

Source: Texas Parks and Wildlife Department, 2008. 
187

APPENDIX D. 

CHAPTER 4 TABLES AND FIGURES 
189

Table D.1.

Structure and Rig Damage Caused by Hurricanes Ivan, Katrina, and Rita

 Ivan Katrina Rita 

Platforms destroyed 7 44 69 

Platforms extensively damaged 20 20 32 

Rigs adrift 5 6 13 

Rigs destroyed 1 4 4 

Rigs extensively damaged 4 9 10 

 Source: Kaiser and Kasprzak, 2008. 

Table D.2.

Louisiana Artificial Reef Program Structure Donations (1987-2006)

 

Year No. Structures Total Donation 

($) 

Average Donation 

($/structure) 

1987 1 250,000 250,000 

1988 4 350,000 87,500 

1990 4 875,000 218,750 

1991 4 1,292,870 323,218 

1992 10 1,326,876 132,688 

1993 13 1,132,404 87,108 

1994 17 1,266,442 74,497 

1995 5 564,840 112,968 

1996 4 736,280 184,070 

1997 8 1,167,385 145,923 

1998 4 327,641 81,911 

1999 11 4,274,657 386,605 

2000 12 1,757,244 146,437 

2001 3 145,000 48,333 

2002 9 1,244,136 138,237 

2003 12 4,103,981 341,998 

2004 14 3,384,689 241,764 

2005 6 2,223,326 370,554 

2006 6 2,820,102 470,017 

Total 147 29,242,874 198,931 

 Source: Louisiana Department of Wildlife and Fisheries, 2009. 
190

Table D.3.

Special Artificial Reef Site Projects and Platform Additions

Area/Block Source Donor Date WDSSa WDRSa Event/Rational 

ST-86 ST-86b ODECO 9/20/91 91 91 Hurricane Juan 

WD-134 WD-134A BOEMRE 9/12/65 280 280 Hurricane Betsy 

WD-134 WD-134B Kirby 1/21/92 280 280 Addition 

WD-134 WD-138 Shell 6/4/92 275 275 Addition 

WD-134 WD-133 Elf 4/17/93 280 280 Addition 

WD-134 SP-54 Vastar 6/2/99 297 282 Addition 

WD-134 SP-78 Texaco 4/25/02 280 274 Addition 

WD-134 WD-122C Maritech 8/12/04 227 280 Addition 

GI-9 GI-9 Freeport 1/14/99 52 52 Construction accident 

GI-9 AODc AOD 1/31/99 51 51 Sunk during construction 

MP-243 MP-243A Coastal 6/22/00 196 196 Hurricane Georges 

MP-243 MP-243B Coastal 6/22/00 196 196 Addition 

MP-243 MP-243A Coastal 6/22/00 196 196 Addition 

MP-243 MP-198A El-Paso 10/10/00 196 196 Addition 

EI-313 Penrod60c None 6/19/72 0 236 

EI-313 EI-313A Texaco 8/3/00 236 236 Biological Study 

EI-313 EI-313A Texaco 8/3/00 236 236 Biological Study 

EI-313 EI-295 POGO 9/30/02 211 236 Addition 

EI-313 EI-335 Murphy 9/8/04 272 236 Addition 

EI-313 EI-231CB Chevron 9/9/04 219 236 Addition 

EI-313 EI-315B Newfield 12/20/05 250 250 Addition 

EI-309 EI-309 Forest 9/18/03 225 225 Biological Study/ 

Hurricane Lili 

EI-324 EI-324 Newfield 9/23/03 265 256 Biological Study/ 

Hurricane Lili 

EI-273 EI-273 Forest 4/24/04 191 191 Biological Study/ 

Hurricane Lili 

EI-322 EI-322AP BP 6/22/04 255 255 Biological Study/ 

Hurricane Lili 

EI-322 EI-322AD BP 6/22/04 255 255 Biological Study/ 

Hurricane Lili 

SP-89 SP-89 Marathon 7/01/04 393 393 Deepwater Reef Criteria 

EI-384 EI-384 W&T 4/28/05 431 431 Deepwater Reef Criteria 

VE-395 VE-395 W&T 7/28/05 428 428 Deepwater Reef Criteria 

 Source: Louisiana Department of Wildlife and Fisheries, 2009. 

 Footnote: a) WDSS = water depth source site; WDRS = water depth reef site. 

 b) Drilling rig. 

 c) Derrick barge. 
191

Table D.4.

Special Artificial Reef Sites Approved in 2006

Area/Block Water Depth (ft) Donor Approval No. Platforms RPI 

WD-117C 214 AngloSwiss June 2006 5 40 

SS-269A 206 Maritech June 2006 3 18 

WD-103/104 223 Apache June 2006 3 24 

EC-222 124 ERT June 2006 2 16 

VE-255 158 Stone June 2006 2 16 

EI-276 176 Chevron June 2006 3 18 

VE-245 128 Chevron June 2006 3 24 

GI-40/48 90 BP Nov 2006 8 64 

ST-161 117 Apache Nov 2006 3 24 

SMI-108 183 Stone Nov 2006 3 18 

 Source: Louisiana Department of Wildlife and Fisheries, 2009.
192

 Figure D.1. Hurricane Katrina and Rita Tracks Relative to Offshore Oil and Gas 

Infrastructure. 

Source: USDOI, MMS, 2005c.
193

 Figure D.2. Structures Destroyed in Hurricanes Ivan, Katrina, and Rita.
194

 

 Figure D.3. Before and After - Devon Energy’s SA-1 Platform 

Destroyed at South Marsh 128. 

Source: Kaiser and Kasprzak, 2008.
195

 Figure D.4. Before and After - BT Operating Company Platform 

 Destroyed at Eugene Island 294A. 

Source: Kaiser and Kasprzak, 2008.
196

Figure D.5. Model Rendition of Hurricane Destroyed Structure Lying Horizontally on the 

Seafloor. Note the Bent Conductors Entering the Seabed. 

Source: Twatchman Snyder and Byrd, Inc., 2008.
197

 

 

 Figure D.6. Model Rendition of Hurricane Destroyed Structure Lying Horizontally on 

 the Seafloor. 

Source: Twatchman Snyder and Byrd, Inc., 2008.
198

 Figure D.7. Louisiana Special Artificial Reef Sites 1991-2005 and Approved in

 2006. 

Source: Louisiana Department of Wildlife and Fisheries, 2009. 
199

APPENDIX E. 

CHAPTER 5 TABLES AND FIGURES
201

Table E.1. 

 

Advantages and Disadvantages of Different Logistical Options for 

Open Ocean Mariculture 

Option Advantages Disadvantages 

Land-Based Crews  Lowest capital costs 

 Maybe best choice for 

near shore (under 10 

km) sites 

 No 24-hour on-site 

security 

 Long response times 

for emergencies 

 High fuel costs for 

long distance sites 

 Limited access in 

poor weather 

 Limited economies of 

scale 

Feed Buoys/Barges  Relatively low capital 

costs 

 Reduced trip 

frequency and fuel 

costs 

 No 24-hour on-site 

security 

 Long response times 

for emergencies 

 May require larger 

service vessels 

Lift-Boat  24-hour on site 

security 

 Access in most 

weather conditions 

 Minimum hurricane 

risk 

 Low 

decommissioning 

liability 

 High capital costs 

 High Operating Costs 

Platform-Based Crews  Best option for 

economies of scale 

 Access in almost all 

weather conditions 

 High capital costs 

 High 

decommissioning 

liability 
202

Table E.2. 

 Summary of Platform-Based Mariculture Projects in the United States 

Project Location Time Technology Species Status 

Texas Sea 

Grant Project 

Texas 1990s Net-Pen Redfish Ceased 

SeaFish 

Mariculture 

LLC 

Texas 1998-

1999 

Cages Red Drum Ceased 

Grace 

Platform 

Project 

California 2003-

2005 

Cages California 

Yellowtail, 

California 

Halibut 

Abandoned

GMIT Project Texas 1998- Cages Cobia, Redfish 

Amberjack, Red 

Porgy 

Financing 

OAC Project Mississippi 2000-

2002 

Cages Red Drum Abandoned

Table E.3. 

Projected Sales and Revenues for GMIT Project (million $) 

 Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 

Sales 5.9 18.5 44.6 83.3 101.1 127.2 144.2 

Net Income -1.5 7.2 19.7 30.1 36.2 46.1 52.1 

Capital 

Expenditure 

20.2 1.5 2.0 1.0 1.0 1.0 1.0 

 Source: BioMarine Technologies Company, 2000. 
203

 Figure E.1. Artist Conception of Platform-Based Mariculture Operation. 

Source: Reggio, 1996. 
204

Figure E.2. Net-Pen and Submerge Cage. 

Source: USDOC, NOAA, 2007. 

Note: The cage on the left is an anchor tensioned cage while the picture on the right is an example of a semi rigid cage. 
205

 

 Figure E.3. Distribution of Existing Fixed Platforms by Depth (2008). 

Note: The lines represent 25 and 50 m contour lines. Figure does not include caissons. 

Data Source: USDOI, MMS, 2008b. 
206

 Figure E.4. Extent of the GOM Hypoxia Zone in 2007. 

Note: Darker shading indicates lower O2 concentrations. 

Data Source: USDOI, MMS, 2008b. 
207

 Figure E.5. Paths of Major Hurricanes Impacting the Gulf Coast from 1983 to 2004. 

Data Source: USDOI, MMS, 2008b. 
208

 

 Figure E.6. Distribution of Platforms by Age. 

Note: Black dots indicate fixed platforms built after 2000. White boxes indicate platforms built 

between 1990 and 1999. X’s indicate platforms built before 1990. 

Data Source: USDOI, MMS, 2008b. 
209

 Figure E.7. Ship Traffic Lanes and Fixed Platforms. 

Data Source: USDOI, MMS, 2008b. 
210

 Figure E.8. Preferred Platforms for Use in OOA with 25 and 50 m Contours. 

Data Source: USDOI, MMS, 2008b. 
211

APPENDIX F. 

CHAPTER 6 TABLES AND FIGURES 

 
213

Table F.1.

Inflation Adjusted Cost Estimates for Offshore Mariculture 

 

Citation Method Species Break-Even 

Production Price 

($/kg) 

Profitable? 

(Lisac and 

Muir, 2000) 

Theoretical model Sea Bass/ 

Seabream 

7.55 Yes (With EU 

support) 

(Lisac and 

Muir, 2000) 

Empirical data Sea Bass/ 

Seabream 

6.82 (range 4.19 

-11.23) 

Yes 

(Kam et al., 

2003) 

Theoretical model Pacific Threadfin 8.76 No 

(Ryan, 

2004) 

Theoretical model Atlantic Salmon 2.6 -3.4 Yes 

Cobia 4.28 Generally No 

Red Snapper 4.28 No 

(Posadas 

and Bridger, 

2003) 

Theoretical model 

Red Drum 4.28 No 

(Lipton and 

Kim, 2007) 

Theoretical model Rock Bream 8.51 Yes 

Mussels 0.77 Yes 

Sea Scallops Not reported Yes 

Cod 2.02 Yes 

Atlantic Salmon 2.02 Yes 

(Kirkley, 

2008) 

Theoretical model 

Flounder 3.53 Yes 

(Jin, 2008) Theoretical model Cod 2.25 Yes 

Salmon 2 Yes 

 Note: Jin (2008) and Kirkley (2008) use the same methods and assumptions and generate similar 

results; these results should not be considered independent. 
214

Table F.2. 

 Assumptions of Theoretical Cost Studies of OOA 

Study Species FCR Interest 

Rate (%) 

Feed Price ($/mt) 

Fingerling Cost ($) 

Stocking Density (kg/m3) 

Final Density (kg/m3) 

Ratio Final Density: Stocking Density 

Cage Cost ($/m3) 

OffsFaci

(Lipton and Kim, 2007) 

Rock Bream 1.3 2.8 1,600 0.40 0.564 12.7 22.5 89 Non

(Posadas and Bridger, 2003) 

Cobia, Red Snapper, Red Drum 

1.5 5 910 1.54 0.178 20-30 112.3 50 Jack 

barg

(Kam et al., 2003) Pacific 

Threadfin 

2.39 10 1,250 0.27 0.109 13.32 122.2 27 Non

(Lisac and Muir, 2000) 

Sea Bass/ Seabream 

2.3 5 916 0.73 0.72 16 22.2 75 (includes 

boats) 

Non

(Jin, 2008) Cod 1.5 7 600 0.85 1.5 35.4 23.6 15 Non

Salmon 1.5 7 730 1.5 1.35 33.8 25.0 15 Non

(Kirkley, 2008) Flounder 1.5 7 650 2 13 25 1.9 15 NonModel A (this paper) 

Cobia 1.5 20 1,000 2 0.012 3.78 315 20 Platf

Model B (this paper) 

Cobia 1.5 20 1,000 2 0.1 22.5 225 20 Platf
215

Table F.3.

Summary of Basic Assumptions 

 Model A Model B 

 Unit Pessimistic Expected Optimistic Pessimistic Expected Optimistic 

Cost of Platform Million $ 2 1.7 1.4 2 1.7 1.4 

# Cages 2 4 8 2 4 8 

Volume of Each 

Cage 

m3 39,270 39,270 39,270 39,270 39,270 39,270 

Cost of Each Cage $/m3 35 20 8 35 20 8 

Cost of Vessel 1000 $ 1,218 1,218 1,218 1,218 1,218 1,218 

Cost of Vehicles 1000 $ 235 235 235 235 235 235 

Fingerling Size kg 0.02 0.02 0.02 0.02 0.02 0.02 

Initial Density kg/m3 0.012 0.012 0.012 0.1 0.1 0.1 

Final Density kg/m3 3.78 3.78 3.78 15 22.5 27 

Price per Fingerling $ 2.00 2.00 2.00 2.00 2.00 2.00 

Transportation Cost 

of Each Fingerling 

$ 1.00 0.50 0.25 1.00 0.50 0.25 

Feed Cost 

(Bulk Rate) 

$/mt 1,000 1,000 1,000 1,000 1,000 1,000 

FCR 1.7 1.5 1.3 1.7 1.5 1.3 

Veterinary Costs $/kg 

$/fingerling 

0.033 0.033 0.033 

0.25 0.25 0.25 

Uneaten Feed Rate % 15 8 1.40 15 8 1.40 

Survival Rate % 90 90 90 75 80 90 

Growth Rate kg/yr 6.5 6.5 6.5 4 5 6 

Harvesting Cost $/kg 0.088 0.088 0.088 0.088 0.088 $0.088 

Ex-vessel Price $/kg 4.44 4.88 5.55 4.44 4.88 5.55 

# Workers 8 16 32 8 16 32 

Annual Salary of 

Each Worker 

$ 50,000 50,000 50,000 50,000 50,000 50,000 

Annual Salary of 

Manager 

$ 110,000 110,000 110,000 110,000 110,000 110,000 

Annual Salary of 

Supervisor 

$ 70,000 70,000 70,000 70,000 70,000 70,000 

Cost of Capital % 30 20 10 30 20 10 

Depreciation Time years 10 10 10 10 10 10 

Tax Rate % 35 35 35 35 35 35 

Inflation Rate % 2.75 2.75 2.75 2.75 2.75 2.75 

Project Life Time years 10 10 10 10 10 10 

Contingency 

Capital Cost 

% 20 15 10 20 15 10 

Efficiency Gain % 3 5 7 3 5 7 
216

Table F.4. 

Fish Feed Prices of Top 3 Suppliers in 2007 

 Nutreco Cermaq BioMar 

Revenue (millions) 1193 EURO 5922 NOK 5000 DKK

Production (million 

tons) 

1.300 0.847 0.700 

Average Exchange 

Ratea

1.35EURO/USD 0.17 USD/NOK 0.18 USD/DKK

Average Price ($/mt)b 1238 1188 1285

 Footnote a) Adopted exchange rate is the average exchange rate in 2007. 

 b) Price as of 2007. 

 Sources: BioMar Group, 2007; Cermaq, 2007; Nutreco, 2007. 

 

Table F.5. 

Cage Cost Estimate (2007) 

Name Type Cost ($/m3

)

a

Sea Station Submersible Cage 38.36 

FarmOcean Floating Cage 87.68 

SADCO Shelf Floating Cage 98.64 

Dunlop Tempest Net-pen 21.92 

Aqualine Offshore Net-pen 8.77 

 Footnotes: Price inflation-adjusted to 2007. 

 Source: Hendrix, 2005. 
217

Table F.6. 

Calculation for Fingerling and Feed Model A 

 Pessimistic Expected Optimistic

Number of Cages 2 4 8

Volume per Cage (m3) 39,270 39,270 39,270

Cost of Net-Pen or Cage 

 ($/m3

) 

35 20 8

Growth Rate (kg/yr) 6.5 6.5 6.5

Production (kg/m3) 3.78 3.78 3.78

Total Production(lb) 654,498 1,308,997 2,617,994

Price per Fingerling ($) 2.00 2.00 2.00

Transportation Cost ($/fingerling) 1.00 0.50 0.25

Survival Rate 90% 90% 90%

Number of Fingerlings Needed 50,748 101,497 202,994

FCR 1.70 1.50 1.30

Uneaten Feed Rate 15% 8% 1%

Feed Requirements (lbs) 1,454,441 2,371,371 3,835,240
218

Table F.7. 

Capital Costs for Models A and B ($1,000) 

 Pessimistic Expected Optimistic 

Cost of Platform 2,000 1,700 1,400 

Total Cost of Net-Pen or Cage 2,749 3,142 2,513 

Land (Base Camp) 94 94 94 

Permitting 118 118 118 

Engineering and Legal Fees 353 353 353 

Removal of Oil Production 

Equipment 

1,000 1,000 1,000 

Other Consultants 118 118 118 

Building 118 118 118 

Maintenance Shop 177 177 177 

Loading Dock with Crane 589 589 589 

Fuel Storage and Loadout 

Facilities 

118 118 118 

Camp Equipment 118 118 118 

Vehicles 235 235 235 

Vessels 1,218 1,218 1,218 

Contingency Capital Cost 20% 15% 10% 

Total Capital Costs 10,804 10,461 8,985 
219

Table F.8. 

Average Operating Costs Over 10-Year Project Lifetime ($1,000) 

 Model A Model B 

 Pessimistic Expected Optimistic Pessimistic Expected Optimistic 

Manager 129 129 129 129 129 129 

Supervisor 82 82 82 82 82 82 

Employees 471 942 1,883 471 941 1,883 

Fingerling Cost 101 203 406 785 1,571 3,142 

Fingerling 

Transportation 

51 51 51 393 393 393 

Farm Insurance 200 200 200 200 200 200 

Other Insurance 129 129 129 129 129 129 

Feed Costs 660 1,076 1,740 2,356 5,122 11,184 

Veterinary 22 44 89 98 196 393 

Harvesting 26 52 105 104 276 746 

Fuel 59 118 235 118 118 118 

Equipment 

Maintenance 

294 294 294 294 294 294 

Platform 

Maintenance 

235 235 235 235 235 235 

Surety Bond 200 200 200 200 200 200 

Operations 353 353 353 353 353 353 

Other 88 88 88 88 88 88 

Total 3,102 4,198 6,221 6,037 10,330 19,570 
220

Table F.9. 

Net Present Value Results, Model A 

 Pessimistic Expected Optimistic 

Ex-Vessel Price ($/kg) 4.4 4.8 5.5 

Production (kg) 294,524 589,048 1,178,097 

Total Revenue ($ million) 1.295 2.880 6.545 

Accumulated Cash Flow from 

Operating Activities ($ million) 

-6.13 -1.08 12.99 

Net Present Value ($ million) -12.87 -11.27 -1.54 

 

Table F.10. 

Net Present Value Results, Model B 

 Pessimistic Expected Optimistic 

Ex-vessel price ($/kg) 4.44 4.88 5.55

Production (kg) 1,178,100 3,141,600 8,482,320

Total Revenue (($ million) 5.230 15.331 47.076

Accumulated Cash Flow from 

Operating Activities ($ million) 

-4.608 38.969 205.961

Net Present Value ($ million) -9.524 8.594 120.1

Table F.11.

Comparison of Financial Performances of Expected 

Scenario (Model A) and Rent Scenario ($1,000) 

 Expected Rent 

Capital Costs 10,461 7,064 

Operating Cost in the First Fiscal 

Year 

4,198 4,333 

Accumulated Cash Flow from 

Operating Activities ($ million) 

-1.077 -1.905 

Net Present Value ($ million) -11.27 -7.951 
221

Table F.12. 

Break-Even Analysis Showing the Value for Parameters at Which NPV Is Zero

Model Scenario Original 

NPV Positive?a

Production (kg/m3) 

Growth Rate (kg/year) 

Cost of Capital (%) 

Product Price ($/kg) 

FCR Platform 

Cost (Million $) 

SurRat

A Rent No 57.3 NAb 10.17 NA NA A Optimistic No 20.88* 6.3 5.88* 0.95 NA NA A Expected No 66 NA 11.91 NA NA NA A Pessimistic No 255 NA 12.17 NA NA NA B Optimistic Yes 5.5* 1.22 190 2.01 5.76 140 18%B Expected Yes 14* 3.52* 39.4 3.87* 2.5* 10.5 56%B Pessimistic No 35* 9.35 NA 8.82 NA NA NA 

a. The column “Original NPV Positive?” is meant as a reference to determine if the NPV decreased (Yes) or in

change. 

* Values with * suggest that the necessary parameter value is realistic. 

b. NA suggests that any plausible value is not capable of making NPV positive. For example, NA might indi

greater than 100% is needed. Blank values suggest that the value is not incorporated into the model. 
222

Table F.13.

Sensitivity Analysis of Model B, Expected Case 

 Unit Slope (change in 

NPV/change in unit) 

Growth Rate kg/year 5,819,900 

Platform Cost $ -0.98 

Cage cost $/m3 -154,135 

Survival % 363,744 

Contingency capital cost % -7,760,479 

Product prices $/kg 8,561,196 

Fingerling cost $ -1,844,576 

FCR -8,019,896 

Initial stocking density kg/m3 240,269,164 

Insurance Premium $ -2.34 
223

 Figure F.1. Sensitivity of NPV to Changes in Contingency Capital Cost, Cost of Capital, 

 and Initial Stocking Density. Model B, Expected Case. 
224

 Figure F.2. Relationship Between Stocking Density and FCR in Model B, Expected 

 Scenario. 

Note: Area below the curve represents parameter value combinations for 

which NPV is positive. Area above the curve represents parameter value 

combinations for which NPV is negative. The curve delinates parameter 

combinations for which NPV is 0. 
225

 Figure F.3. NPV Break-Even Relationship Between Stocking Density and Growth Rate 

 in Model B, Expected Scenario. 

Note: Area below the curve represents parameter value combinations for 

which NPV is negative. Area above the curve represents parameter value 

combinations for which NPV is positive. The curve delinates parameter 

combinations for which NPV is 0. 
226

 Figure F.4. NPV Break-Even Relationship Between Stocking Density and Survival Rate in 

 Model B, Expected Scenario. 

Note: Area below the curve represents parameter value combinations for which 

NPV is negative. Area above the curve represents parameter value combinations 

for which NPV is positive. The curve delinates parameter combinations for which 

NPV is 0. 
227

APPENDIX G. 

CHAPTER 7 TABLES AND FIGURES 
229

Table G.1.

Operational Commercial Offshore Wind Farms in Europe as of August 2008 

 Wind Farm Year Built Capacity 

(MW) 

Depth 

 (m) 

Developer Foundation 

Type 

Turbine Size 

(MW) 

Distance 

to Shore 

(km) 

Sourcesa

Vindeby 1991 5 3.5 SEAS gravity 0.45 1.5 1, 3, 9, 4 

Lely 1994 2 7.5 Energie Nord 

West 

mono 0.5 0.8 1, 3, 6, 1, 9, 

12, 4 

Tuno Knob 1995 5 4 Midtkraft 0.5 3 1, 3, 5, 12, 4 

Dronten 1996 11 1.5 Nuon mono 0.6 0.03 1, 3, 8, 9, 12 

Bockstigen 1997 3 6 mono 0.55 1, 3, 4 

Blyth 2000 4 8.5 Nuon, Shell, 

E.ON 

 2 1 1, 3, 4 

Middlegrunden 2001 40 6 Energie E2 gravity 2 2 1, 3, 4, 15 

Utgrunden 2001 10 8.6 Vattenfall mono 1.425 1, 3, 4, 12 

Yttre Stengrund 2001 10 8 Vattenfall mono 2 1, 3, 4, 5 

Horns Rev 2002 160 10 Vattenfall mono 2 14 1, 3, 6, 9, 12 

Frederikshaven 2003 10 4 1 suction, 3 

mono 

3 0.2 1, 9, 12 

Nysted 2003 158 7.75 DONG gravity 2.3 10 1, 12 

Samso 2003 23 20 mono 2.3 3.5 1, 3, 5 

North Hoyle 2003 60 12 Npower mono 2 7 1, 12 

Ronland 2003 17.2 1 2.3 0.1 1, 3 

Scroby Sands 2004 60 16.5 E.ON mono 2 2.5 1, 14 

Arklow 2004 25 3.5 Airtricity mono 3.6 10 1, 3 

ems emden 2004 4.5 3 Enova 4.5 0.04 1, 13 

Kentish Flats 2005 90 5 Vattenfall mono 3 10 1, 12 

Barrow 2006 90 17.5 DONG mono 3 7.5 1, 5, 6, 9 

Egmond aan Zee 2006 108 18 Nuon mono 3 10 1, 14 

Rostock 2006 2.5 2 2.5 0.5 1, 9, 12 

Burbo Bank 2007 90 5 DONG mono 3.6 6.5 1, 12 

Beatrice 2007 10 45 Talisman jacket 5 22 12 

Lillgrund 2007 110 7 Vattenfall gravity 2.3 10 6 

Q7 2007 120 21.5 Econcern mono 2 23 16 

 Footnote: (a) 1= Lemming et al., 2007; 3= Beurskens and Noord, 2003; 4= Barthelmie and Pryor, 2001; 5= 

Power-Technology, 2008; 6= Vattenfall, 2008; 8= DONG Energy, 2008; 9=A2sea, 2008; 10= 

IEA, 2005; 11= Airtricity, 2008; 12=OffshoreWindEnergy.org, 2007; 13= Enova, 2008; 14= 

Gerdes et al., 2007. 15= Larsen et al., 2005; 16=Econcern, 2008. 
230

Table G.2.

Approved Offshore Wind Farms in Europe as of May 2008 

Name Country Capacity 

(MW) 

Number 

of 

Turbines 

Turbine Distance 

to Shore 

(km) 

Status Developer 

Thornton Bank Belgium 300 60 RePower 

5 MW 

28 Under 

Construction 

C-Power 

Belwind Belgium 330 110 Vestas 

V90 

42 Approved ECONCERN/Evelop 

Eldepasco Belgium 180-252 36 38 Approved 

Cote d' Albatre France 105 21 Multibrid 

M5000 

6 Under 

Construction 

ENERTRAG 

Rodsand II Denmark 200 92 2 Approved E.ON. 

Horns Rev II Denmark 200 91 27 Under 

Construction 

DONG 

London Array England 1,000 341 various 20 Approved DONG Energy / Shell 

Wind Energy / E.On 

Inner Dowsing England 90 27 Siemens 5 Under 

Construction 

Centrica Renewable 

Energy Ltd 

Lynn England 97 30 Siemens 5 Under 

Construction 

Centrica Renewable 

Energy Ltd 

Rhyl Flats England 90 25 3.6 MW 8 Under 

Construction 

Npower renewables 

Solway Firth (Robin 

Rigg) 

England 180 60 3 MW 10 Under 

Construction 

E.ON UK Renewables 

Greater Gabbard England 500 140 Siemens 

SWT 3.6 

26 Approved Airtricity 

Gunfleet Sands England 172 48 Siemens 

SWT 3.6 

7 Approved DONG Energy 

Scarweather Sands England 100 30 3.6 MW 6 Approved DONG Energy/ E.ON 

UK 

Thanet England 300 83 11 Approved Warwick Energy 

Amrumbank West Germany 400 80 5 MW 36 Approved Amrumbank West 

GmbH 

Borkrum-West II Germany 400 80 Multibrid 

M5000 

45 Under 

Construction 

Alpha Ventus Germany 60 12 Multibrid 

M5000 

45 Under 

Construction 

Bard Offshore Germany 400 80 5 MW 89 Approved Bard Engineering 

GmbH 

Gode Wind Germany 400 80 33 Approved Plambeck Neue 

Energien AG 

Global Tech I Germany 400 80 93 Approved Nordsee Windpower 

GmbH 

Nordsee Ost Germany 1,250 80 30 Approved WINKRA Offshore 

Nordsee Planungs- und 

Dan Tysk Germany 400 80 70 Approved GEO mbh 

Baltic I Germany 57.5 21 2.0 - 5.0 

MW 

15 Approved Offshore Ostsee Wind 

AG 
231

Table G.2. 

Approved Offshore Wind Farms in Europe as of May 2008

(continued) 

Name Country Capacity 

(MW) 

Number 

of 

Turbines 

Turbine Distance 

to Shore 

(km) 

Status Developer 

Kriegers Flak Germany 320.5 80 3.6 - 5.0 

MW 

31 Approved Offshore Ostsee Wind 

AG 

Hochsee Windpark, 

He dreiht

Germany 400 80 85 Approved EOS Offshore AG 

Hochsee Windpark 

Nordsee

Germany 400 80 90 Approved EOS Offshore AG 

Offshore- Windpark 

Nordergründe

Germany 125 25 13 Approved 

Nördlicher Grund Germany up to 

2,010 

up to 402 86 Approved GEO mbH, renergys 

GmbH 

Meerwind Germany 1,350 270 3.6 - 5.0 

MW 

15-80 Approved Windland Energie 

Sandbank 24 Germany 4,720 980 Up to 5 

MW 

90 Approved Sandbank 24 GmbH 

Wilhelmshaven Germany 4.5 1 <10 m Approved Winkra-Energie 

GmbH 

Offshore NorthSea 

Windpower

Germany 1,255 251 39 Approved Enova Offshore 

Arkona Becken Südost Germany 1,005 201 35 Approved AWE- ArkonaWindpark- EntGEOFReE Germany 25 5 Approved GEO mbh 

Ventotec Ost 2 Germany 600 200 104 Approved Arcadis Consult 

GmbH 

Borkum Riffgrund 

West 

Germany 280 80 50 Approved Energien AG 

Offshore- BürgerWindpark Butendiek

Germany 240 80 37 Approved OSB Offshore 

Borkum Riffgrund Germany 231 77 34 Plambeck Neue 

Energien AG 

Source: DENA, 2008; The Crown Estate, 2008; OffshoreWindEnergy.org, 2007; Michel et al., 2007. 

Note: Table does not include planned but not yet approved wind farms. 
232

Table G.3.

Distribution of Offshore Wind Farms by Country as of August 2008 

Country Number wind 

farms

Capacity 

(MW)

% Capacity Planned 

capacity (MW) 

Denmark 8 418 23 400 

UK 9 674 37 2,529 

Sweden 4 133 7 

Netherlands 4 241 13 

Ireland 1 25 1.3 

Germany 2 7 0.3 16,733 

Belgium 1 300 16.7 810 

Total 29 1,798 

 Source: Tables G.1 and G.2. 
233

Table G.4.

Proposed Offshore Wind Projects in the U.S. as of August 2008 

Developer Wind Park Location Number 

Turbines 

Project Size (MW) 

Depth (m) 

Distance to Shore (km) 

S

EMI Cape Wind Cape Cod 130 450 0.15 - 18 10.5 DWEST Galveston 

Offshore Wind 

Galveston 50-60 150 16 11 L

Deepwater Wind Plum Island Long Island 2-3 10 4-11 0.5 A

a

FPL Long Island 

Wind Park 

Long Island 40 150 15-20 5.8 O

SRE/Babcock and Brown 

Padre Island South Texas 100+ 500 C

Patriot Renewables 

South Coast Wind 

Buzzards Bay, Massachusetts 

90-120 300 Under 20 2 C

BlueWater Wind Delaware 450 19 ASouthern Company Georgia 3-5 10 E

Bc

Hull Municipal Hull Offshore 

Wind 

Massachusetts 4 12-20 7-14 2 A

p

Deepwater Wind Rhode Island ~100 ~385 A

n

Deepwater Wind Garden State 

Offshore Energy 

New Jersey 96 350 ~30 R

Radial Wind Radial Wind Park Lake Michigan 390 1,950 25 

 Source: Musial and Ram, 2008. 
234

Table G.5.

Economic Incentives for Offshore Wind Development in Europe 

Denmark UK Germany Netherlands Belgium 

Feed in 

Price 

Negotiable: 

recently 13.2 

€/kWh 

9.1 €/kWh Premium 

likely to be 

over 0.28 

€/kWh 

Tax 

Exemptions 

Exempt from 

20 €/tonne 

carbon tax 

4.3 p/kWh Yes Yes 

Renewable 

Energy 

Credits 

~ 5 p/kWh 0.108 €/kWh 

for first 216 

MW 

Other 

Subsidies 

 Construction 

grants 

 Government 

pays some of 

cable costs, 

resource 

assessment 

costs 

Renewable 

Goal for 

2020 

30% 15% 18% 14% 13% 

 Source: EREC, 2007a and b. 
235

Table G.6.

Regulations for Leasing Land for Offshore Wind Development in Europe and the U.S. 

Nation Denmark Germany UK Texas U.S.

Fee None None One time 

lease fee of 

up to 

£500,000 

3.5 to 5.5% 

royalty 

during 

operation 

2% of gross 

revenue 

Term 25 years 25 years Up to 50 

years 

30 years 30 years 

Competition lowest 

feed-in 

price 

first-come 

first-served 

quality of 

proposal 

monetary 

benefit to 

state 

monetary 

benefit to state 

Selection of 

Sites by 

Regulators

Yes No Yes Yes Mixed 

 Sources: Peloso, 2006; BSH, 2008; Texas General Land Office, 2007a and b; USDOI, BLM, 

 2006; The Crown Estate, 2008. 

Table G.7.

Ten Largest Manufacturers of Turbines in 2006 

Company Nation Market Share 

GE U.S. 15.3% 

Vestas Denmark 27.4% 

Enercon Germany 14.2% 

Gamesa Spain 15.5% 

Suzlon Netherlands 7.5% 

Siemens Germany 7.1% 

Nordex Germany 3.3% 

REPower Germany 3.2% 

Mitsubishi Japan 1.0% 

Goldwind China 2.8% 

 Source: WWEA, 2007. 
236

 Figure G.1. Cumulative Capacity of the U.S. and European Onshore Wind Industry. 

Source: AWEA, 2008 and EWEA, 2007. 
237

 Figure G.2. Cumulative Capacity of European Offshore Wind Farms. 

Source: Data from Table G.1. 
238

Figure G.3. Operational and Planned Offshore Wind Farms as of 2007. 

Operational Wind Farms 

Wind Farms Under 

Construction 

Source: EWEA, 2007. 

Note: Lillgrund and Q7 are now operational. 
239

Figure G.4. Increasing Size of Development of European Offshore Wind Farms Over Time. 

Source: Data from Table G.1. 
240

 Figure G.5. Increasing Depth of European Offshore Wind Farms Over Time. 

Source: Data from Table G.1. 
241

 Figure G.6. Increasing Turbine Capacity of European Offshore Wind Farms Over Time. 

Source: Data from Table G.1. 
242

Figure G.7. Increasing Distance to Shore of European Offshore Wind Farms Over Time. 

 

Source: Data from Table G.1. 
243

 Figure G.8a. Rows of Turbines at Nysted with Sailboat in Foreground. 

Source: Nysted Offshore Windfarm, 2008. 
244

 Figure G.8b. Row of Turbines at North Hoyle Showing Transition Piece Painted Yellow for 

 Navigational Purposes. 

Source: BWEA, 2008. 
245

 Figure G.8c. Grid Arrangement of Horns Rev Wind Farm. 

DONG Energy, 2008. 
246

 Figure G.8d. Aerial View of Kentish Flats. 

Source: Elsam, 2008. 
247

Figure G8e. Burbo Bank Offshore Wind Farm. 

Source: Siemens, 2008. 
248

 Figure G.8f. Scroby Sands. 

Source:Hueper, 2008. 
249

 Figure G.9. Middlegrunden Offshore Wind Farm Showing Curved Arrangement. 

Source: Wind Turbines, 2008. 
250

 Figure G.10. Layout of Horns Rev II Wind Farm. 

Source: DONG Energy, 2008. 
251

 Figure G.11. Electrical Service Platform at Lillgrund. 

Source: NyTeknik, 2007. 
252

 Figure G.12. Monopile after Installation by Jack-Up Barge Resolution at Kentish Flats. 

Source: Elsam, 2008. 
253

Figure G.13. Nacelle and Blades Being Lifted In Bunny Ear Configuration at Kentish Flats. 

Source: Elsam, 2008. 
254

 Figure G.14. Beatrice Jacket Foundation. Note People in Foreground for Scale. 

Source: Talisman Energy, 2008. 
255

 Figure G.15. Sinking of a Jacketed Foundation for the Beatrice Project. 

Source: Talisman Energy, 2008. 
256

 Figure G.16. Lifting of the Beatrice Turbine and Foundation. 

Source: Talisman Energy, 2008. 
257

 Figure G.17. Connection of the Beatrice Turbine Tower and Foundation. 

Source: Talisman Energy, 2008. 
258

Figure G.18. Gravity Foundations at Nysted. 

. 

Source: DEA, 2005.
259

 Figure G.19. Monopile for Use at Kentish Flats. 

Source:Elsam, 2008. 
260

 Figure G.20. Approximate Location of Cape Wind Offshore Wind Farm. 

. 
261

 Figure G.21. Annual Average of World Offshore Wind Resources. 

Source: USDOE, NREL, 2008. 
262

 Figure G.22. Wind Speeds in Europe. 

Source: Wind Atlases of the World, 2008. 
263

 Figure G.23. Wind Speeds in the U.S. 

Source: USDOE, NREL, 2008. 
264

 

 Figure G.24. Population Density of Europe. 

Source: SEDAC, 2008. 
265

 Figure G.25. Population Density of the U.S. 

Source: SEDAC, 2008. 
267

APPENDIX H. 

CHAPTER 8 TABLES AND FIGURES 
269

Table H.1.

 

Summary of Arguments for and Against Offshore Wind and Comparison to Onshore Wind 

Arguments Against 

Offshore Wind 

Applies to 

Onshore 

Wind 

Power 

Validity 

Ruins special/historic 

seascape 

Y Aesthetics subjective, but wind turbines are visual disamenity to most. No effect 

on property values. 

Kills birds Y Expected death rate 1 to 10 birds per MW. Difficult to compare effects of wind 

and fossil fuels on bird populations on a per MWh basis. 

Harms fisheries N Likely to be significant impacts on local fisheries during construction, especially 

if monopiles are used. During operation fishing success may increase. 

Harms marine 

mammals 

N Likely to have impacts on marine mammals during construction, especially if 

monopiles are used, potentially including mortality. During operation impacts 

will be negligible. 

Requires subsidies Y Offshore wind power not economically competitive with onshore wind or fossil 

fueled power. 

Conflicts w/ shipping 

& navigation 

N Site dependent. USACE must permit projects and decide if they conflict with 

navigation. 

Hurts tourism N Offshore wind projects have caused net increases in tourism. 

Arguments For 

Offshore Wind 

Power 

 

Mitigates climate 

change 

Y Wind power produces very little greenhouse gas emissions over its life cycle. 

Decreases water use Y Each MW of wind capacity can offset 0.7 to 2.1 million gallons of water 

consumed per year 

Improves air quality Y Cape wind estimated to prevent 11 mortalities per year (Kempton et al., 2005), but 

depends on fuel mix of power actually displaced. 

Reduces foreign fuel 

dependence 

Y Roughly 50% of U.S. electricity comes from coal; U.S. exports more coal than it 

imports. Roughly 20% of electricity from natural gas. Roughly 20% of this 

natural gas is imported, almost entirely from Canada. 

Creates jobs Y The Cape Wind project will create about 50 permanent jobs, plus 100 indirect 

jobs. Construction will create several hundred additional jobs. 

Creates electrical price 

stability 

Y Wind power provides price stability since cost of producing energy can be 

forecast, but even most ambitious forecasts only imagine 20% of U.S. electricity 

supply to come from wind in 2030. 

Close to population 

centers 

N Offshore sources are closer to population centers than onshore wind sources, but it 

is probably cheaper to build new transmission systems from high-wind onshore 

sites. 

Higher winds offshore N Winds are more powerful offshore, but COE of offshore wind is higher than COE 

of onshore wind, suggesting that higher wind speeds do not make up for higher 

capital costs. 

Reduced user conflicts N Site and plan specific; seems to be occurring in Texas, not in Cape Cod. 

 Source: Firestone and Kempton, 2007; Firestone et al., 2007; USDOI, MMS, 2008a. 
270

Table H.2.

Capital Costs and Cost of Energy of Offshore Wind Farms 

Wind Farm or Type 

of Estimate 

Year of 

Prediction/Estimate 

Cost of 

Energy 

($/MWh) 

Capital 

Costs 

($/kW) 

Source 

Generating Costs of 

Coal Fired Electricity 

2003 49 Sims et al., 2003 

National Average 

Wholesale Price of 

Power (primarily 

coal, gas and nuclear) 

2008 58 Wiser and Bolinger, 

2008 

Generic Estimate 

Based on Empirical 

Data (onshore) 

2008 40 1,710 Wiser and Bolinger, 

2008 

Generic Estimate 

Based on Small Set 

of Empirical Data 

2005 40-95 1,600-2,600 IEA, 2005b 

Theoretical w/ 3MW 

Turbine 

2006 95 2,100 Fingresh et al., 2006 

Theoretical 500 MW 

Farm, 5 MW 

Turbines, 15 miles 

from Coast 

2004 54 1,200 Musial and Butterfield, 

2004 

LIOWP (cancelled) 2007 291 5,231 PACE, 2007 

Generic Estimate for 

Future Wind Farm 

2007 4,000 PACE, 2007 

General Based on 

Empirical Data 

2007 100 3,200 DTI, 2004 

Cape Wind 2007 122 Mense, 2007 

Estimates from 

Proposed Wind 

Farms 

2001 48-70 Barthelmie and Pryor, 

2001 

Generic Estimate 

Based on All 

Available Empirical 

Data 

2008 3,354 Data in Table 3 

Middelgrunden 2005 70 Larsen et al., 2005 

Theoretical Generic 

Estimate 

2006 3,500 Lemming et al., 2007 

Empirical Data 2003 2,200-2,600 Morgan et al., 2003 
271

Table H.3.

Costs of Offshore Wind Farms in Europe 

Wind Farm Nation Year 

Constructed 

Capacity 

(MW) 

Total 

Costa

(million) 

Depth 

(m) 

Turbine 

size 

(MW) 

Number 

of 

Turbines 

Distance 

to Shore 

(km) 

Sourcesb

Vindeby Denmark 1991 5 11.2 3.5 0.45 11 1.5 1, 3, 7, 4 

Lely Netherlands 1994 2 4.8 7.5 0.5 4 0.8 1, 3, 6, 

1, 7, 10, 

4 

Tuno Knob Denmark 1995 5 11.2 4 0.5 10 3 1, 3, 5, 

10, 4 

Dronten Netherlands 1996 11 28.6 1.5 0.6 19 0.03 1, 3, 7, 

10 

Bockstigen Sweden 1997 3 4.8 6 0.55 5 1, 3, 4 

Blyth UK 2000 4 7 8.5 2 2 1 1, 3, 4 

Middlegrunden Denmark 2001 40 53 6 2 20 2 1, 3, 4, 

13 

Utgrunden Sweden 2001 10 14 8.6 1.425 7 1, 3, 4, 

10 

Yttre 

Stengrund 

Sweden 2001 10 18 8 2 5 1, 3, 4, 5 

Horns Rev Denmark 2002 160 500 10 2 80 14 1, 3, 6, 

7, 10 

Nysted Denmark 2003 158 373 7.75 2.3 72 10 1, 10 

Samso Denmark 2003 23 52 20 2.3 10 3.5 1, 3, 5 

North Hoyle UK 2003 60 148 12 2 30 7 1, 10 

Ronland Denmark 2003 17.2 26 1 2.3 8 1, 3 

Scroby Sands UK 2004 60 155 16.5 2 30 2.5 1, 12 

Arklow Ireland 2004 25 70 3.5 3.6 7 10 1, 3 

Kentish Flats UK 2005 90 217 5 3 30 10 1, 10 

Barrow UK 2006 90 190 17.5 3 30 7.5 1, 5, 6, 7 

Egmond aan 

Zee 

Netherlands 2006 108 334 18 3 36 10 1, 12 

Burbo Bank UK 2007 90 185 5 3.6 25 6.5 1, 10 

Beatrice UK 2007 10 70 45 5 2 22 10 

Lillgrund Sweden 2007 110 300 7 2.3 48 10 6 

Q7 Netherlands 2007 120 590 21.5 2 60 23 14 

Lynn/Inner 

Downsing 

UK 2008 90 600 9.5 3.6 54 5 5 

Robin Rigg UK 2008 180 765 5 3 60 9 5 

Throton bank Belgium 2008 300 1,250 14 5 60 27 1 

Footnote: (a) Adjusted for inflation using the Bureau of Labor Statistics calculator and exchange rates at the time of 

 construction. 

 (b) 1= Lemming et al., 2007; 3= Beurskens and Noord, 2003; 4= Barthelmie and Pryor, 2001; 5= Power 

Technology, 2008; 6= Vattenfall, 2008; 7=A2sea, 2008; 8= IEA, 2005a; 9= Airtricity, 2008; 

10=OffshoreWindEnergy.org, 2007; 11= Enova, 2008; 12=Gerdes et al., 2007. 13= Larsen et al., 2005; 

14=Econcern, 2008. 
272

Table H.4.

Parameter Estimates from the Three Best Models from Multiple Regressions 

Total Cost (million $) = β0 + β1*(year) + β2*(distance to shore (m)) + β3*(turbine size(MW)) + β4

*(capacity (MW)) + β5*(water depth (m)) 

Parameter Model 1 Model 2 Model 3 

β0 -21,029 (0.2281) 18.02 (0.6929) -19,293 (0.2890) 

β1 10.53 (0.2271) 9.66 (0.2887) 

β2 9.28 (0.015) 9.97 (0.0007) 8.43 (0.0111) 

β3 -56.14 (.0204) -39.06 (0.0346) -57.68 (0.0229) 

β4 2.45 (<0.0001) 2.65 (<0.0001) 2.53 (<0.0001) 

β5 1.05 (0.5825) 

Adj R2 0.92 (<0.0001) 0.91 (<0.0001) 0.91 (<0.0001) 

 Note: P-values reported in parentheses. 
273

Table H.5.

Environmental Impacts Associated with Cape Wind Development According to the EIS 

Affected Resource Construction Impactsa

 Operation Impacts 

Oceanography Currents No measurable impacts Minor 

Waves No measurable impacts No measurable impacts 

Salinity No measurable impacts No measurable impacts 

Temperature No measurable impacts No measurable impacts 

 Sediment transport Minor Minor 

 Water depth Minor Minor 

Birds Raptors No measurable impacts No measurable impacts 

Passerines Minor No measurable impacts to 

Minor 

Coastal species No measurable impacts to 

Minor 

No measurable impacts to 

Moderate 

Marine birds Minor to moderate Minor to moderate 

Invertebrates Benthic invertebrates Minor Minor 

 Shellfish Minor Minor 

Plankton No measurable impacts Minor 

Fisheries Finfish Minor No measurable impacts to 

Minor 

Demersal eggs and 

larvae 

Moderate No measurable impacts to 

Moderate 

Fish habitat No measurable impacts to 

Minor 

No measurable impacts to 

Minor 

Marine Mammals Marine Mammals Minor to moderate No measurable impacts to 

Moderate 

Endangered Species Sea Turtles No measurable impacts to 

Minor 

No measurable impacts to 

Minor 

Cetaceans No measurable impacts to 

Minor 

No measurable impacts to 

Minor 

Birds No measurable impacts to 

Minor 

No measurable impacts to 

Moderate 

Source: USDOI, MMS, 2008a. 

Footnote: (a) Minor impacts are those that can be completely mitigated against or are small enough that the resource 

can recover completely on its own. Moderate impacts occur if either the impact is immitigable but the 

resource could recover on its own, or if the impact can be partially mitigated and the resource could 

then recover on its own. Major impacts occur if the impact is immitigable, the viability of the 

resource is threatened and the resource would not fully recover. 
274

 Figure H.1. Costs of Onshore and Offshore Wind. 

Sources: Dept. for BERR, 2004; ODE, 2007; Morgan et al., 2003; Fingersh et al., 2006; Musial et al., 2006. 
275

 

 Figure H.2. Capital Costs Versus Turbine Size. 

 Figure H.3. Capital Costs as a Function of Wind Farm Size. 

Source: Data in Table H.3. 

Source: Data in Table H.3. 
277

APPENDIX I. 

CHAPTER 9 TABLES AND FIGURES 
279

Table I.1.

Major Lease Terms and Components for Selected Offshore Wind Regulatory Authorities 

Sources: Toke, 2007; DEA, 2007 and 2008; USDOI, BLM, 2006; Texas General Land Office, 2007a; USDOI, 

MMS, 2009. 

Major Issue UK Denmark BLM (onshore) Texas BOEMRE 

Lease Terms: 

Leasing Fees and 

Royalties, Phased 

Access 

Developers pay 

application fee of £2,500 

and one time lease fee of 

up to £500,000 

depending on size of site. 

Developers are eligible 

for capital grants; exempt 

from climate change levy 

(4.3 p/kWh), can sell 

renewable obligation 

credits (5p/kWh; Toke 

2007). 

Price of electricity 

agreed upon in tender. 

Recent tender price 

13.2 c/kWh. No 

phased access. Lessees 

have three years from 

lease to construct wind 

farm. 

Phased access 

system granting 

data collection and 

competitive 

exclusion rights. 

Fee for commercial 

development 

$2,365 per MW of 

capacity. 

Phased access 

in which 

developer has 

right to 

terminate lease. 

$20,000 phase 

1 fee and 3.5 to 

5.5% royalty 

during 

operation. 

First 5 years of 

lease used for 

assessment. 

Royalty rates and 

bonus bids vary 

competitively. 

Term Limit 40 or 50 years with a 

renegotiation after 20 or 

25 years 

25 years None 30 years 30 years 

Competitive 

Process 

Government selects sites 

with input from 

developers. Process has 

preceded in rounds, not 

unlike BOEMRE five 

year plans. 

Set lease areas and hold 

competitive bidding. 

First come-first 

served basis. 

Competing 

applicants 

encouraged to form 

cooperative 

agreement. 

Set lease areas 

and hold 

competitive 

bidding. 

Competitive auction 

for sites with 

competitive interest. 

Use highest bonus 

bid or royalty rate. 

Approval Criteria Feasibility of 

development plan. 

Lowest feed in price 

per kWh. 

 Highest bidder. Highest bidder. 

Environmental 

Analyses 

BERR completed SEA 

for areas to be leased. 

Developers complete 

EIS for sites. 

Developer conducts site 

specific EIS after 

competition. 

Exceptions may be 

made by DEA. 

Use CX’s for data 

monitoring and EA 

for commercial 

development. 

Occasional use of 

EIS. 

Has to comply 

with COE 

NEPA 

requirements. 

Has to conduct 

avian and bat 

studies if EIS is 

not required. 

Multiple 

opportunities for 

environmental 

analysis. Site 

specific EIS usually 

required. 

Operational 

Issues: 

Environmental 

and Compliance 

Monitoring, 

Safety 

Developers conduct 

monitoring and submit 

reports. 

Each developer submits 

operational plans and 

conducts their own 

environmental 

monitoring. 

Little discussion of 

operational issues. 

Monitoring 

conducted by 

lessee with 

reports issued 

to state. 

Developers conduct 

monitoring 

according to 

approved plan and 

issue reports. 

BOEMRE conducts 

inspections. 

Decommissioning Surety bonds or other 

financial instrument 

required. Allow for 

repowering or reuse of 

facilities. 

Developer must submit 

approved financial 

guarantee to DEA. 

Bonds are required; 

amount of bond 

determined on site 

specific basis. 

Surety bonds, 

cash deposit or 

letter of credit 

required. 

Surety bond or 

other guarantee 

required. Detailed 

decommissioning 

plan does not need 

to be submitted 

until 2 years before 

end of lease. 
280

Table I.2.

Texas Royalty System 

 Preproduction Years 1-8 Years 9-16 Years 17-30 

Minimum 

Royalty 

0 3.5% 4.5% 5.5% 

Minimum 

Annual Royalty 

per MW 

 $4,100 $5,500 $7,000 

Other fees $20,000 per 

year 

(approximately 

$1 per acre) 

 

 Source: Texas General Land Office, 2007a. 
281

 Figure I.1. Flow Chart of Texas Regulatory Process. 

Government select sites and conducts competition 

Developers submit phase 

2 plan 

Environmental and resource 

monitoring 

Phase 1 permit 

Rivers and Harbors permit 

for Met towers with 

Categorical Exclusion or 

Environmental Assessment 

Selection of best proposal 

Production 

End lease and decommissioning 

3-5 years 

20-40 years 

1-2 years 

Construction 

30 years 

2-3 years 

Rivers and Harbors permit 

for wind farm with 

Environmental Impact 

Statement or 

Environmental 

Assessment 

Source: Texas General Land 

 Office, 2007a. 
282

 Figure I.2. Flow Chart of BLM Regulatory Process. 

Developers select sites 

Resource evaluation permit 

Categorical Exclusion or Environmental 

Assessment 

Resource 

monitoring 

Application for Development Permit 

End lease and decommissioning 

Categorical Exclusion, Environmental 

Assessment or Environmental Impact 

Statement 

Development Permit

3 years 

1-2 years 

30-35 years 

1-2 years Construction 

Production 

1 year 

Source: USDOI, BLM, 2006.