OCS Study 

BOEM 2013-0112 

Coastal Marine Institute 

Offshore Drilling Industry and 

Rig Construction Market in the 

Gulf of Mexico 

U.S. Department of the Interior

Bureau of Ocean Energy Management 

Gulf of Mexico OCS Region 

Cooperative Agreement

Coastal Marine Institute 

Louisiana State University 
U.S. Department of the Interior Cooperative Agreement 

Bureau of Ocean Energy Management Coastal Marine Institute 

Gulf of Mexico OCS Region Louisiana State University 

OCS Study 

BOEM 2013-0112 

Coastal Marine Institute 

Offshore Drilling Industry and 

Rig Construction Market in the 

Gulf of Mexico 

Authors 

Mark J. Kaiser 

Brian Snyder 

Allan G. Pulsipher 

 March 2013 

Prepared under BOEM Cooperative Agreement 

M08AC12773 

by 

Louisiana State University 

Center for Energy Studies 

Coastal Marine Institute 

Baton Rouge, Louisiana 70803 

Published by 
iii 

DISCLAIMER 

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however, exempt from review and compliance with BOEM editorial standards. 

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To order a CD, use the Gulf of Mexico OCS Region contact information below and reference 

OCS Study BOEM 2013-0112. To download a pdf copy, use the Environmental Studies Program 

Information System (ESPIS) and search on the study report number. In the near future, you will 

also be able to get this report also from the National Technical Information Service. 

U.S. Department of the Interior

Bureau of Ocean Energy Management

Gulf of Mexico OCS Region

Public Information Office (GM 217G) 

1201 Elmwood Park Blvd. 

New Orleans, Louisiana 70123-2394 

Phone: (504) 736-2519, 1-800-200-GULF 

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Web site: http://www.ntis.gov/

CITATION 

Kaiser, M.J., B. Snyder, and A.G. Pulsipher. 2013. Offshore drilling industry and rig 

construction market in the Gulf of Mexico. U.S. Dept. of the Interior, Bureau of Ocean 

Energy Management, Gulf of Mexico OCS Region, New Orleans, LA. OCS Study 

BOEM 2013-0112. 375 p. 
v

ABSTRACT 

Mobile offshore drilling units (MODUs) are a critical element of the offshore oil and gas 

industry. Drilling rig markets have a large geographic expanse and are economically important 

with large labor impacts. The purpose of this report is to describe the MODU industry and the 

economic impacts of rig construction in the U.S. We emphasize dayrates in the service market 

and capital expenditures in the newbuild market because these are primary metrics and basic 

indicators of the industry. The industrial organization and major players in the contract drilling 

market are described and business strategies among contractors illustrated. Dayrates in the 

contract drilling market are analyzed and hypotheses regarding dayrate factors are tested. The 

major shipyards in the newbuild market are described along with the geographic distribution of 

construction and the status of the market circa 2011. A brief description of the processes of 

jackup rig construction is provided, including design tradeoffs and the drilling equipment 

installed. The construction costs of jackup rigs in the U.S. are analyzed and the labor, equipment, 

and material cost components are estimated. Factors that influence capital costs are discussed 

and the newbuild and replacement costs of jackups, semisubmersibles, and drillships are 

analyzed. 
vii

TABLE OF CONTENTS 

LIST OF FIGURES ...................................................................................................................................... XV

LIST OF TABLES ...................................................................................................................................... XXI

EXECUTIVE SUMMARY ................................................................................................................................... 25

1. MOBILE OFFSHORE DRILLING UNITS ................................................................................................ 29

1.1. MODU FUNCTION ..................................................................................................................... 29 

1.1.1. Well Type ........................................................................................................................... 29

1.1.2. Drilling a Well ................................................................................................................... 29

1.1.3. Completions and Workovers .............................................................................................. 29

1.1.4. Well Configuration ............................................................................................................ 30

1.1.5. Well Depth, Pressure, and Temperature ........................................................................... 30

1.2. RIG CLASSIFICATION ................................................................................................................. 30 

1.2.1. Rig Type ............................................................................................................................. 30

1.2.2. Environmental Capacity .................................................................................................... 31

1.2.3. Water Depth ....................................................................................................................... 32

1.2.4. Specification ...................................................................................................................... 32

1.3. JACKUPS .................................................................................................................................... 32 

1.3.1. Design Elements ................................................................................................................ 32

1.3.2. Independent vs. Mat ........................................................................................................... 33

1.3.3. Cantilevered vs. Slot .......................................................................................................... 33

1.4. SEMISUBMERSIBLES .................................................................................................................. 33 

1.4.1. Station Keeping .................................................................................................................. 33

1.4.2. Motion Compensation ........................................................................................................ 33

1.4.3. Displacement ..................................................................................................................... 34

1.4.4. Generations ........................................................................................................................ 34

1.4.5. Upgrading .......................................................................................................................... 36

1.5. DRILLSHIPS ................................................................................................................................ 36 

1.5.1. Early Drillships ................................................................................................................. 36

1.5.2. Modern Drillships .............................................................................................................. 36

1.5.3. Displacement ..................................................................................................................... 37

1.5.4. Competition with Semis ..................................................................................................... 37

1.6. ACTIVITY STATES ...................................................................................................................... 37 

1.6.1. Active ................................................................................................................................. 37

1.6.2. Ready-Stacked .................................................................................................................... 37

1.6.3. Cold-Stacked ...................................................................................................................... 38

1.6.4. Dead-Stacked ..................................................................................................................... 38

1.6.5. Retired................................................................................................................................ 38

1.7. RIG COSTS ................................................................................................................................. 38 

1.7.1. Newbuild Costs .................................................................................................................. 39

1.7.2. Replacement Costs ............................................................................................................. 39

2. THE FIVE OFFSHORE RIG MARKETS .................................................................................................. 41

2.1. RIG MARKETS ............................................................................................................................ 41 

2.1.1. Organization ...................................................................................................................... 41
viii

2.1.2. Contract Drilling Services Market .................................................................................... 17

2.1.3. Newbuild Market ............................................................................................................... 17

2.1.4. Upgrade Market ................................................................................................................. 17

2.1.5. Secondhand Market ........................................................................................................... 17

2.1.6. Scrap Market ..................................................................................................................... 17

2.1.7. Cash Flows ........................................................................................................................ 18

2.1.8. Market Size ........................................................................................................................ 18

2.2. CONTRACT DRILLING MARKET................................................................................................. 18

2.2.1. System Measures ................................................................................................................ 18

2.2.2. Players ............................................................................................................................... 19

2.2.3. Prices ................................................................................................................................. 19

2.2.4. Market Size ........................................................................................................................ 20

2.2.5. Market Value ..................................................................................................................... 20

2.3. NEWBUILD MARKET.................................................................................................................. 21

2.3.1. System Measures ................................................................................................................ 21

2.3.2. Players ............................................................................................................................... 21

2.3.3. Prices ................................................................................................................................. 21

2.3.4. Market Size ........................................................................................................................ 22

2.3.5. Market Value ..................................................................................................................... 22

2.4. UPGRADE MARKET.................................................................................................................... 23

2.4.1. System Measures ................................................................................................................ 23

2.4.2. Players ............................................................................................................................... 23

2.4.3. Prices ................................................................................................................................. 23

2.4.4. Market Size ........................................................................................................................ 24

2.4.5. Market Value ..................................................................................................................... 24

2.5. SECONDHAND MARKET............................................................................................................. 24

2.5.1. System Measures ................................................................................................................ 24

2.5.2. Players ............................................................................................................................... 25

2.5.3. Prices ................................................................................................................................. 25

2.5.4. Market Size ........................................................................................................................ 25

2.5.5. Market Value ..................................................................................................................... 25

2.6. SCRAP MARKET......................................................................................................................... 26

2.6.1. System Measures ................................................................................................................ 26

2.6.2. Players ............................................................................................................................... 26

2.6.3. Prices ................................................................................................................................. 26

2.6.4. Market Value ..................................................................................................................... 26

3. THE OFFSHORE CONTRACT DRILLING MARKET-SUPPLY, UTILIZATION, AND DAYRATES .......29

3.1. DATA SOURCES ......................................................................................................................... 29

3.1.1. Utilization and Supply ....................................................................................................... 29

3.1.2. Dayrates ............................................................................................................................. 29

3.2. SUPPLY ...................................................................................................................................... 29

3.3. GEOGRAPHIC DISTRIBUTION ..................................................................................................... 30

3.3.1. Regional Characteristics ................................................................................................... 30

3.3.2. Active Rigs ......................................................................................................................... 31

3.3.3. Contracted Rigs ................................................................................................................. 31

3.4. UTILIZATION.............................................................................................................................. 32

3.4.1. World Trends ..................................................................................................................... 32

3.4.2. Regional Trends ................................................................................................................. 32

3.4.3. Interregional Correlations ................................................................................................. 33

3.4.4. Market Conditions May Act to Reduce High Utilization ................................................... 33
ix

3.5. DAYRATES................................................................................................................................. 34

3.5.1. Trends ................................................................................................................................ 34

3.5.2. Interregional Correlations ................................................................................................. 34

3.5.3. Dayrate Volatility .............................................................................................................. 35

3.6. CONTRACTS............................................................................................................................... 35

3.6.1. Dayrate vs. Turnkey ........................................................................................................... 35

3.6.2. Term vs. Well ..................................................................................................................... 36

3.7. CUSTOMERS............................................................................................................................... 36

3.8. CONCLUSIONS ........................................................................................................................... 37

4. THE OFFSHORE CONTRACT DRILLING MARKET–OWNERSHIP, VALUATION, AND MARKET

STRUCTURE ..............................................................................................................................................39

4.1. DATA SOURCES ......................................................................................................................... 39

4.2. OWNERSHIP ............................................................................................................................... 39

4.2.1. Public Firms ...................................................................................................................... 39

4.2.2. State-Owned Firms ............................................................................................................ 40

4.2.3. Private Firms ..................................................................................................................... 40

4.2.4. Market Share ..................................................................................................................... 41

4.3. VALUATION ............................................................................................................................... 41

4.3.1. Revenue .............................................................................................................................. 41

4.3.2. Fleet Value ......................................................................................................................... 41

4.3.3. Debt ................................................................................................................................... 42

4.4. PRODUCT DIFFERENTIATION ..................................................................................................... 43

4.4.1. Regional Concentration ..................................................................................................... 43

4.4.2. Customer Concentration .................................................................................................... 44

4.4.3. Age ..................................................................................................................................... 44

4.4.4. Specification and Water Depth .......................................................................................... 44

4.4.5. Net Revenue by Rig Class .................................................................................................. 44

4.5. NEWBUILDING STRATEGIES ...................................................................................................... 45

4.5.1. Speculative Newbuilding.................................................................................................... 45

4.5.2. Firm Size ............................................................................................................................ 46

4.6. MARKET STRUCTURE ................................................................................................................ 47

4.6.1. Mergers and Acquisitions .................................................................................................. 47

4.6.2. Barriers to Entry ................................................................................................................ 47

4.6.3. Consolidation ..................................................................................................................... 48

4.6.4. Measures of Industry Concentration ................................................................................. 48

4.6.5. Firm Competition ............................................................................................................... 49

4.7. CONCLUSIONS ........................................................................................................................... 49

5. EMPIRICAL ANALYSIS OF FACTORS IMPACTING DAYRATES........................................................51

5.1. HYPOTHESES ............................................................................................................................. 51

5.2. METHODOLOGY......................................................................................................................... 52

5.2.1. Data Source ....................................................................................................................... 52

5.2.2. Categorization ................................................................................................................... 52

5.2.3. Approach ............................................................................................................................ 53

5.3. DEMAND FOR DRILLING RIGS IS POSITIVELY ASSOCIATED WITH OIL PRICES ......................... 54

5.4. DAYRATES INCREASE WITH INCREASING OIL PRICES............................................................... 55

5.5. DAYRATES AND UTILIZATION RATES ARE POSITIVELY CORRELATED..................................... 56

5.6. HIGH SPECIFICATION RIGS CHARGE HIGHER DAYRATES THAN LOW SPECIFICATION DRILLING 

RIGS ........................................................................................................................................................ 57

5.6.1. Drilling Depth .................................................................................................................... 57
x

5.6.2. Water Depth ....................................................................................................................... 58

5.6.3. Station Keeping .................................................................................................................. 58

5.6.4. Regional Control ............................................................................................................... 58

5.7. LONG-TERM CONTRACTS ARE MORE EXPENSIVE THAN SHORT-TERM CONTRACTS............... 59

5.8. NOCS PAY HIGHER DAYRATES THAN IOCS OR INDEPENDENTS .............................................. 60

5.9. LARGE DRILLING CONTRACTORS ARE AWARDED HIGHER DAYRATES THAN SMALLER 

CONTRACTORS........................................................................................................................................ 61

5.10. DEEPWATER APPRAISAL DRILLING RECEIVES HIGHER DAYRATES THAN EXPLORATORY OR 

DEVELOPMENTAL DRILLING .................................................................................................................. 61

5.11. LIMITATIONS ........................................................................................................................... 62

5.12. CONCLUSIONS AND IMPLICATIONS.......................................................................................... 63

6. CONCEPTUAL MODELS OF FIRM DECISION-MAKING .....................................................................65

6.1. NEWBUILDING ........................................................................................................................... 65

6.1.1. Model ................................................................................................................................. 65

6.1.2. Outyear Utilization Rate .................................................................................................... 67

6.1.3. Parameterization ............................................................................................................... 68

6.1.4. Model Results ..................................................................................................................... 68

6.1.5. Sensitivity ........................................................................................................................... 69

6.1.6. Limitations ......................................................................................................................... 70

6.2. STACKING.................................................................................................................................. 71

6.2.1. Decision Model .................................................................................................................. 71

6.2.2. Parameterization ............................................................................................................... 72

6.2.3. Model Results ..................................................................................................................... 73

6.2.4. Limitations ......................................................................................................................... 73

6.3. NET ASSET VALUE .................................................................................................................... 74

6.3.1. Definition ........................................................................................................................... 74

6.3.2. Model ................................................................................................................................. 74

6.3.3. Model Results ..................................................................................................................... 75

6.3.4. NAV Comparison ............................................................................................................... 75

6.3.5. Alternative Formulations ................................................................................................... 75

7. JACKUP CONSTRUCTION MARKETS ................................................................................................. 77

7.1. HISTORICAL OVERVIEW ............................................................................................................ 77

7.2. DEMAND FACTORS .................................................................................................................... 78

7.2.1. Oil Prices ........................................................................................................................... 78

7.2.2. Utilization and Dayrates .................................................................................................... 78

7.2.3. Technology ......................................................................................................................... 78

7.2.4. New Discoveries ................................................................................................................ 78

7.2.5. Fleet Age ............................................................................................................................ 78

7.2.6. Construction Cost .............................................................................................................. 79

7.3. PLAYERS.................................................................................................................................... 79

7.3.1. Singapore ........................................................................................................................... 79

7.3.2. China ................................................................................................................................. 80

7.3.3. South Korea ....................................................................................................................... 80

7.3.4. United States ...................................................................................................................... 81

7.4. BUYERS ..................................................................................................................................... 82

7.5. CONTRACTS............................................................................................................................... 82

7.5.1. Product Specification ......................................................................................................... 82

7.5.2. Payment Schedule .............................................................................................................. 83

7.5.3. Unforeseen Events and Risk .............................................................................................. 83
xi

8. NONTECHNICAL PRIMER ON JACKUP DESIGN ................................................................................85

8.1. DESIGN PROCESS....................................................................................................................... 85

8.2. NOTABLE FEATURES ................................................................................................................. 85

8.3. JACKUP DESIGN FIRMS.............................................................................................................. 86

8.4. DESIGN FACTORS ...................................................................................................................... 86

8.4.1. Number of Legs .................................................................................................................. 86

8.4.2. Leg Length ......................................................................................................................... 86

8.4.3. Environmental Conditions ................................................................................................. 86

8.4.4. Leg Type ............................................................................................................................. 87

8.4.5. Chord Number and Type.................................................................................................... 87

8.4.6. Rack Chocks ....................................................................................................................... 88

8.4.7. Footing Structure ............................................................................................................... 88

8.4.8. Slot and Cantilevered Systems ........................................................................................... 88

8.5. JACKUP DESIGN CLASSES.......................................................................................................... 89

8.5.1. Common U.S. Built Designs .............................................................................................. 89

8.5.2. Common Internationally Built Designs ............................................................................. 90

9. JACKUP RIG CONSTRUCTION ............................................................................................................93

9.1. WORKFLOW............................................................................................................................... 93

9.2. SPUDCANS ................................................................................................................................. 93

9.3. HULL.......................................................................................................................................... 93

9.4. TOPSIDES ................................................................................................................................... 94

9.5. RACKS AND HALF-ROUNDS ...................................................................................................... 94

9.6. CHORD ASSEMBLY .................................................................................................................... 94

9.7. LAUNCHING............................................................................................................................... 95

9.8. DERRICK AND CANTILEVER ...................................................................................................... 95

9.9. LEG ASSEMBLY ......................................................................................................................... 95

9.10. DELIVERY AND CLASSIFICATION ............................................................................................ 95

10. MODU RIG EQUIPMENT ......................................................................................................................97

10.1. MODU SYSTEMS..................................................................................................................... 97

10.2. DRILLING................................................................................................................................. 97

10.3. DRILLING EQUIPMENT............................................................................................................. 98

10.3.1. Derrick ............................................................................................................................. 98

10.3.2. Topdrive ........................................................................................................................... 98

10.3.3. Drawworks ....................................................................................................................... 98

10.4. MUD SYSTEMS......................................................................................................................... 99

10.4.1. Mud Pumps ...................................................................................................................... 99

10.4.2. Solids Control .................................................................................................................. 99

10.5. BLOWOUT PREVENTER.......................................................................................................... 100

10.6. PIPE HANDLING ..................................................................................................................... 100

11. JACKUP RIG WEIGHT RELATIONS ................................................................................................. 101

11.1. WEIGHT MANAGEMENT ........................................................................................................ 101

11.2. WEIGHT FACTORS ................................................................................................................. 101

11.2.1. Water Depth ................................................................................................................... 101

11.2.2. Drilling Depth ................................................................................................................ 101

11.2.3. Environmental Capability .............................................................................................. 101

11.2.4. Rig Design ..................................................................................................................... 102

11.3. DATA SOURCE ....................................................................................................................... 102

11.4. SUMMARY STATISTICS .......................................................................................................... 102
xii

11.5. SINGLE FACTOR MODELS...................................................................................................... 103

11.6. WEIGHT RELATION................................................................................................................ 103

11.7. LIMITATIONS ......................................................................................................................... 104

12. CAPITAL, LABOR, AND MATERIAL REQUIREMENTS FOR JACKUP CONSTRUCTION IN THE

U.S. ...........................................................................................................................................................105

12.1. RIG CONSTRUCTION .............................................................................................................. 105

12.1.1. U.S. Market .................................................................................................................... 105

12.1.2. Cost Components ........................................................................................................... 105

12.2. SUPPLY CHAIN DISTRIBUTION .............................................................................................. 106

12.3. COST ESTIMATION AND ADJUSTMENT .................................................................................. 107

12.4. CAPITAL EXPENDITURES ....................................................................................................... 107

12.4.1. Data Source ................................................................................................................... 107

12.4.2. Rig Construction Cost .................................................................................................... 107

12.4.3. Regression Model .......................................................................................................... 108

12.5. LABOR COST MODULE .......................................................................................................... 108

12.5.1. Labor Cost Relation ....................................................................................................... 108

12.5.2. Wages ............................................................................................................................. 108

12.5.3. Productivity .................................................................................................................... 109

12.6. MATERIAL MODULE.............................................................................................................. 110

12.6.1. Steel Cost Sub-Module ................................................................................................... 110

12.6.2. Engine Sub-Module ....................................................................................................... 111

12.6.3. Other Material Module .................................................................................................. 111

12.7. RIG KIT MODULE .................................................................................................................. 111

12.8. DRILLING EQUIPMENT MODULE ........................................................................................... 111

12.9. PROFIT MODULE.................................................................................................................... 112

12.10. ILLUSTRATION ..................................................................................................................... 112

12.10.1. Capital Costs ............................................................................................................... 112

12.10.2. Labor Costs .................................................................................................................. 112

12.10.3. Material Costs ............................................................................................................. 112

12.10.4. Rig Kit and Drilling Equipment Costs ......................................................................... 113

12.10.5. Profit Margins ............................................................................................................. 113

12.10.6. Cost Distribution ......................................................................................................... 113

12.11. U.S. JACKUP MARKET SIZE................................................................................................. 113

12.11.1. Market Revenue ........................................................................................................... 113

12.11.2. Labor Market ............................................................................................................... 113

12.11.3. Relative Size ................................................................................................................. 114

13. CONSTRUCTION COST FACTORS ..................................................................................................115

13.1. MARKET CONDITIONS ........................................................................................................... 115

13.2. MATERIAL PRICES ................................................................................................................. 115

13.2.1. Cost Distribution ........................................................................................................... 115

13.2.2. Steel................................................................................................................................ 115

13.2.3. Equipment Prices ........................................................................................................... 116

13.3. EXCHANGE RATES................................................................................................................. 116

13.4. LABOR ................................................................................................................................... 117

13.5. DESIGN CLASS....................................................................................................................... 117

13.6. RIG SPECIFICATIONS.............................................................................................................. 118

13.6.1. Structural Weight ........................................................................................................... 118

13.6.2. Water Depth ................................................................................................................... 118

13.6.3. Operating Environment ................................................................................................. 118
xiii

13.6.4. Equipment Specifications ............................................................................................... 118

13.7. CONTRACT TYPE AND OPTIONS ............................................................................................ 119

13.8. SHIPYARD CHARACTERISTICS ............................................................................................... 119

13.9. BACKLOGS............................................................................................................................. 120

14. NEWBUILD AND REPLACEMENT COST FUNCTIONS ...................................................................121

14.1. DATA SOURCES ..................................................................................................................... 121

14.2. SUMMARY STATISTICS .......................................................................................................... 122

14.2.1. Average Cost .................................................................................................................. 122

14.2.2. Cost Variation ................................................................................................................ 122

14.2.3. Rig Age ........................................................................................................................... 122

14.2.4. Water Depth and Environmental Capability ................................................................. 122

14.2.5. Country of Build ............................................................................................................ 123

14.3. MODEL DEVELOPMENT ......................................................................................................... 123

14.3.1. Function Specification ................................................................................................... 123

14.3.2. Variable Description ..................................................................................................... 124

14.3.3. Expectations ................................................................................................................... 124

14.4. NEWBUILD COST MODELS .................................................................................................... 124

14.4.1. Single Variable Models .................................................................................................. 124

14.4.2. Jackups .......................................................................................................................... 124

14.4.3. Semisubmersibles ........................................................................................................... 125

14.4.4. Drillships ....................................................................................................................... 126

14.4.5. Design Class .................................................................................................................. 126

14.5. REPLACEMENT COST MODELS .............................................................................................. 127

14.5.1. Single Variable Models .................................................................................................. 127

14.5.2. Jackups .......................................................................................................................... 127

14.5.3. Semisubmersibles ........................................................................................................... 128

14.5.4. Drillships ....................................................................................................................... 128

14.6. APPLICATION......................................................................................................................... 128

14.7. LIMITATIONS ......................................................................................................................... 129

REFERENCES..........................................................................................................................................131

APPENDIX A CHAPTER 1 TABLES AND FIGURES ............................................................................ 147

APPENDIX B CHAPTER 2 TABLES AND FIGURES ............................................................................ 177

APPENDIX C CHAPTER 3 TABLES AND FIGURES ............................................................................ 197

APPENDIX D CHAPTER 4 TABLES AND FIGURES ............................................................................ 223

APPENDIX E CHAPTER 5 TABLES AND FIGURES ............................................................................ 243

APPENDIX F CHAPTER 6 TABLES AND FIGURES............................................................................. 255

APPENDIX G CHAPTER 7 TABLES AND FIGURES ............................................................................ 269

APPENDIX H CHAPTER 8 TABLES AND FIGURES ............................................................................ 281

APPENDIX I CHAPTER 9 TABLES AND FIGURES.............................................................................. 299

APPENDIX J CHAPTER 10 TABLES AND FIGURES ........................................................................... 309

APPENDIX K CHAPTER 11 TABLES AND FIGURES .......................................................................... 327

APPENDIX L CHAPTER 12 TABLES AND FIGURES .......................................................................... 337

APPENDIX M CHAPTER 13 TABLES AND FIGURES ......................................................................... 353

APPENDIX N CHAPTER 14 TABLES AND FIGURES .......................................................................... 363
xv

LIST OF FIGURES 

FIGURE A.1. CASING DIAGRAM FOR A TYPICAL WELL. ............................................................................. 152

FIGURE A.2. HORIZONTAL, VERTICAL, AND DIRECTIONAL WELL CONFIGURATION. ................................ 153

FIGURE A.3. DEPTH AND WELL CONFIGURATION OF SELECTED OFFSHORE WELLS IN THE U.S. GOM. .... 153

FIGURE A.4. HIGH TEMPERATURE HIGH PRESSURE RESERVOIR CLASSIFICATION. ................................... 154

FIGURE A.5. GLOBAL DISTRIBUTION OF HPHT DRILLING IN 2008. .......................................................... 154

FIGURE A.6. BOTTOM SUPPORTED VERSUS FLOATING RIGS. .................................................................... 155

FIGURE A.7. AN OLD SUBMERSIBLE, A DRILLING BARGE, AND A CANTILEVERED JACKUP DRILLING RIG. 156

FIGURE A.8. FLOATING RIGS. LEFT, THE WEST AQUARIUS, A SEMISUBMERSIBLE; RIGHT, THE WEST POLARIS

DRILLSHIP. ....................................................................................................................... 157

FIGURE A.9. AVERAGE WIND SPEEDS OVER THE OCEAN IN FEBRUARY (TOP) AND JULY (BOTTOM)........ 158

FIGURE A.10. THE HARSH ENVIRONMENT BOB PALMER NEXT TO A MODERATE ENVIRONMENT RIG. ...... 159

FIGURE A.11A. SPECIFICATIONS OF A STANDARD JACKUP (ROWAN JUNEAU)........................................... 160

FIGURE A.11B. SPECIFICATIONS OF A HIGH-SPEC JACKUP (ROWAN EXL III). ........................................... 161

FIGURE A.12. RACK AND PINION ELEVATING SYSTEM OF A F&G SUPER M2 RIG. ................................... 162

FIGURE A.13. SPUDCAN PENETRATING THE SEAFLOOR DURING JACKUP OPERATION. ............................. 163

FIGURE A.14. MAT FOUNDATION. ............................................................................................................. 163

FIGURE A.15. A CANTILEVERED JACKUP RIG OPERATING AT A PLATFORM. ............................................. 164

FIGURE A.16. DIAGRAM OF AN NOV DRILL STRING COMPENSATOR. ....................................................... 165

FIGURE A.17. SEMISUBMERSIBLE GENERATIONS CLASSIFIED ACCORDING TO TRANSOCEAN. ................. 166

FIGURE A.18. THE SEDCO 135-E, A 1

ST GENERATION SEMISUBMERSIBLE, BUILT IN 1967. ..................... 166

FIGURE A.19. THE ESSAR WILDCAT, A 2

ND GENERATION AKER H-3 SEMISUBMERSIBLE, BUILT IN 1977. .. 167

FIGURE A.20. THE OCEAN PATRIOT, A 3

RD GENERATION BINGO 3000 SEMISUBMERSIBLE, BUILT IN 

1983. ............................................................................................................................... 168

FIGURE A.21. THE WEST EMINENCE, A 6

TH GENERATION SEMISUBMERSIBLE, BUILT IN 2009. .................. 169

FIGURE A.22. THE E.W. THORNTON DRILLSHIP BUILT IN 1965. ................................................................ 170

FIGURE A.23. THE GLOMAR III DRILLSHIP BUILT IN 1966. ........................................................................ 171

FIGURE A.24. A MODERN DRILLSHIP, THE 5

TH GENERATION WEST NAVIGATOR, BUILT IN 2000. ............... 172

FIGURE A.25. DUAL ACTIVITY DERRICK ON THE 6

TH GENERATION WEST POLARIS DRILLSHIP BUILT IN 

2008. ............................................................................................................................... 173

FIGURE A.26. SIZE COMPARISON OF THE DISCOVERER ENTERPRISE, DISCOVERER 534, AND TRANSOCEAN 

RICHARDSON, A 4

TH GENERATION SEMI. ........................................................................... 173

FIGURE A.27. TRANSITIONS AMONG RIG ACTIVITY STATES. .................................................................... 174

FIGURE A.28. FOUR COLD-STACKED RIGS IN SABINE PASS, LOUISIANA. ................................................. 174
xvi

FIGURE A.29. THE DEAD-STACKED JACKUP RIG ZEUS BEING DISMANTLED IN FREEPORT, TEXAS........... 175

FIGURE A.30. THE OCEAN WARWICK GROUNDED NEAR DAUPHIN ISLAND, ALABAMA, FOLLOWING 

HURRICANE KATRINA. LATER REBUILT, THE RIG IS CURRENTLY OPERATING. .............. 176

FIGURE B.1. DIRECTION OF CASH FLOW THROUGH OFFSHORE RIG MARKETS. ......................................... 189

FIGURE B.2. SIX MONTH MOVING AVERAGE OF REGIONAL JACKUP AND FLOATER DAYRATES, 2000- 

2011. ............................................................................................................................... 190

FIGURE B.3. NUMBER OF WELLS DRILLED PER YEAR, 1994-2010. ........................................................... 191

FIGURE B.4. GEOGRAPHIC DISTRIBUTION OF THE NUMBER OF OFFSHORE WELLS DRILLED IN 2011. ....... 191

FIGURE B.5. ANNUAL REVENUE OF THE OFFSHORE CONTRACT DRILLING MARKET, 2000-2012. ............. 192

FIGURE B.6. AVERAGE COST OF JACKUP AND FLOATER DELIVERIES BY WATER DEPTH, 2000-2013. ...... 193

FIGURE B.7. DELIVERIES OF NEWBUILD RIGS BY CLASS, 1974-2014. ....................................................... 194

FIGURE B.8. NEWBUILD MARKET SIZE, 2000-2012. .................................................................................. 195

FIGURE C.1. ILLUSTRATION OF THE METHOD USED FOR AVERAGING DAYRATES. ................................... 207

FIGURE C.2. GLOBAL SUPPLY OF NEWBUILD AND EXISTING MODUS IN THE 1Q 2012. ........................... 208

FIGURE C.3. GLOBAL SUPPLY OF MODUS IN THE 1Q 2012. ..................................................................... 209

FIGURE C.4. OFFSHORE DRILLING REGIONS AND 1Q 2011 DRILLING ACTIVITY. ...................................... 210

FIGURE C.5. NUMBER OF ACTIVE RIGS BY REGION, 1987-2012. ............................................................... 211

FIGURE C.6. NATIONAL DISTRIBUTION OF ACTIVE RIGS WITHIN REGIONS, 1987-2012. ........................... 212

FIGURE C.7. RELATIONSHIP BETWEEN THE NUMBER OF CONTRACTED JACKUPS AND THE NUMBER OF 

ACTIVE RIGS IN THE U.S. GOM BY MONTH, 1999-2011.................................................. 213

FIGURE C.8. NUMBER OF CONTRACTED JACKUPS BY REGION, 1999-2012. .............................................. 214

FIGURE C.9. NUMBER OF CONTRACTED FLOATERS BY REGION, 1999-2012. ............................................ 215

FIGURE C.10. SIX MONTH MOVING AVERAGE OF WORLD UTILIZATION RATES, 2000-2011. .................... 216

FIGURE C.11. SIX MONTH MOVING AVERAGE OF JACKUP UTILIZATION RATES IN SELECTED REGIONS,

2000-2011. ...................................................................................................................... 217

FIGURE C.12. SIX MONTH MOVING AVERAGE OF FLOATER UTILIZATION RATES IN SELECTED REGIONS,

2000-2011. ...................................................................................................................... 218

FIGURE C.13. ILLUSTRATION OF THE MOVEMENT OF RIGS IN RESPONSE TO HIGH UTILIZATION RATES. .. 218

FIGURE C.14. RELATIONSHIP BETWEEN UTILIZATION RATE AND THE INCREASE IN MARKET CAPACITY IN 

THE PERSIAN GULF AND SOUTHEAST ASIA, 2000-2011. ................................................ 219

FIGURE C.15. RELATIONSHIP BETWEEN UTILIZATION RATE AND RIG MOVEMENT IN THE NORTH SEA,

2000-2011. ...................................................................................................................... 220

FIGURE C.16. SIX MONTH MOVING AVERAGE OF JACKUP AND FLOATER DAYRATES, 2000-2011. ........... 221

FIGURE C.17. QUARTERLY CHANGE IN AVERAGE DAYRATES IN SELECTED REGIONS, 2000-2011. .......... 222

FIGURE D.1. CONTRACTED DAYS IN GLOBAL OFFSHORE DRILLING MARKET BY COMPANY OWNERSHIP,

2000-2010. ...................................................................................................................... 233
xvii

FIGURE D.2. RELATIONSHIP BETWEEN ENTERPRISE VALUE AND REVENUE AND EARNINGS FOR SELECTED 

DRILLING CONTRACTORS ON DECEMBER 31, 2011. ........................................................ 234

FIGURE D.3. RELATIONSHIP BETWEEN FLEET SIZE AND FLEET VALUE FOR SELECTED DRILLING 

CONTRACTORS ON DECEMBER 31, 2011. ........................................................................ 235

FIGURE D.4. RELATIONSHIP BETWEEN ENTERPRISE VALUE AND FLEET VALUE FOR SELECTED DRILLING 

CONTRACTORS ON DECEMBER 31, 2011. ........................................................................ 235

FIGURE D.5. DEBT TO MARKET CAPITALIZATION OF SEADRILL AND SONGA, 2008-2011. ....................... 236

FIGURE D.6. AVERAGE FLEET AGE AND THE PROPORTION OF THE FLEET STACKED IN DECEMBER 2010. 236

FIGURE D.7. DELIVERY YEAR AND AVERAGE DAYRATES OF JACKUPS AND FLOATERS FROM 2000- 

2010. ............................................................................................................................... 237

FIGURE D.8. INVENTORIES OF JACKUP AND FLOATER FLEETS FOR SELECTED FIRMS IN 2011. ................. 238

FIGURE D.9. RELATIONSHIP BETWEEN FIRM SIZE AND RELATIVE NEWBUILDING EXPENDITURE, 2005-

2011. ............................................................................................................................... 239

FIGURE D.10. SELECTED MERGERS AMONG MAJOR PLAYERS IN THE OFFSHORE DRILLING MARKET, 1990-

2010. ............................................................................................................................... 240

FIGURE D.11. CONSOLIDATION IN THE OFFSHORE CONTRACT DRILLING INDUSTRY, 1984-2010. ............ 241

FIGURE D.12. HERFINDAHL-HIRSCHMAN INDEXOF JACKUP AND FLOATER REGIONAL MARKETS, 2001-

2010. ............................................................................................................................... 242

FIGURE E.1. ILLUSTRATION OF THE METHOD USED FOR AVERAGING DAYRATES. .................................... 251

FIGURE E.2. GLOBAL ACTIVE RIG COUNT AND OIL PRICES, 2001-2011. ................................................... 251

FIGURE E.3. RELATIONSHIP BETWEEN JACKUP AND FLOATER DAYRATES AND OIL PRICES, 2000-2010. . 252

FIGURE E.4. DAYRATES AND UTILIZATION RATE IN THE U.S. GOM JACKUP MARKET. ........................... 253

FIGURE E.5. MODEL RELATIONSHIP BETWEEN UTILIZATION RATES AND DAYRATES IN THREE JACKUP 

MARKETS, 2006-2010. ..................................................................................................... 254

FIGURE E.6. MODEL RELATIONSHIP BETWEEN UTILIZATION RATES AND DAYRATES IN THREE FLOATER 

MARKETS, 2006-2010. ..................................................................................................... 254

FIGURE F.1. DIAGRAM OF THE VARIABLE UTILIZATION MODEL AND STACKING DECISION. ..................... 262

FIGURE F.2. UTILIZATION RATE OVER THE RIG LIFECYCLE IN THE VARIABLE UTILIZATION MODEL. ....... 262

FIGURE F.3. NPV BREAK-EVEN POINTS OF UTILIZATION AND DAYRATES UNDER EXPECTED AND 

OPTIMISTIC ASSUMPTIONS FOR FIXED UTILIZATION. ....................................................... 263

FIGURE F.4. NPV BREAK-EVEN POINTS OF UTILIZATION AND DAYRATES WITH FIXED AND VARIABLE 

UTILIZATION RATES UNDER THE EXPECTED SCENARIO. .................................................. 263

FIGURE F.5. THE IMPACTS OF AN INITIAL TWO YEAR CONTRACT ON BREAK-EVEN DAYRATES AND 

UTILIZATION RATES. ........................................................................................................ 264

FIGURE F.6. SENSITIVITY OF THE BREAK-EVEN DAYRATE FIXED UTILIZATION MODEL TO CHANGES IN 

DISCOUNT RATE. .............................................................................................................. 264

FIGURE F.7. EFFECT OF UTILIZATION ON THE BENEFIT OF THE STACKING VERSUS OPERATING. .............. 265

FIGURE F.8. EFFECT OF STACKING DURATION ON THE BENEFIT OF STACKING VERSUS OPERATING. ....... 265
xviii

FIGURE F.9. SAMPLE NET ASSET VALUES OF SEADRILL FLOATERS AS CALCULATED BY JEFFERIES, 4Q

2011. ............................................................................................................................... 266

FIGURE F.10. NET ASSET VALUE OVER TIME FOR TWO SIMILAR RIGS, NOVEMBER 2008-NOVEMBER 

2011. ............................................................................................................................... 266

FIGURE F.11. RELATIONSHIP BETWEEN NAV AND DAYRATES AND UTILIZATION RATES FOR RIGS OF 

DIFFERENT AGES. ............................................................................................................ 267

FIGURE G.1. JACKUP RIG CONSTRUCTION BY REGION, 1950-2012. .......................................................... 274

FIGURE G.2. JACKUP RIG CONSTRUCTION IN ASIAN COUNTRIES, 1970-2012. .......................................... 274

FIGURE G.3. OIL PRICE AND WORLDWIDE DELIVERY RATES OF JACKUP RIGS AND FLOATING RIGS, 1974-

2012. ............................................................................................................................... 275

FIGURE G.4. RELATIONSHIP BETWEEN THE TWO-YEAR LAGGED OIL PRICE AND NUMBER OF JACKUPS 

DELIVERED, 1975-2012. .................................................................................................. 276

FIGURE G.5. RELATIONSHIP BETWEEN THE TWO-YEAR LAGGED AVERAGE DAYRATE AND NUMBER OF 

JACKUPS DELIVERED, 2000-2012.................................................................................... 277

FIGURE G.6. LAYOUT OF THE KEPPEL FELS SHIPYARD IN SINGAPORE AND SATELLITE VIEW IN 2011. .. 278

FIGURE G.7. SEMBCORP’S JURONG AND PPL SHIPYARDS IN 2012. .......................................................... 279

FIGURE G.8. THE LETOURNEAU VICKSBURG, MISSISSIPPI SHIPYARD. .................................................... 280

FIGURE G.9. THE AMFELS BROWNSVILLE, TEXAS SHIPYARD................................................................. 280

FIGURE H.1. JACKUP RIG DESIGN IS ANALOGOUS TO SHIP DESIGN SPIRAL. .............................................. 285

FIGURE H.2. FOUR COMMON RIG DESIGNS; CLOCKWISE FROM UPPER LEFT: BMC PACIFIC 375; KFELS N

CLASS; LETOURNEAU 240 C; LETOURNEAU SUPER 116E. ............................................. 286

FIGURE H.3. MAIN DECK (LEFT) AND MACHINERY DECK (RIGHT) LAYOUT OF A LETOURNEAU SUPER 

116E. ............................................................................................................................... 287

FIGURE H.4. EARLY JACKUP RIG SEA GEM IN 1964. .................................................................................. 288

FIGURE H.5. SIZE COMPARISON OF THE GUSTO MSC CJ70 CLASS RIG. ................................................... 288

FIGURE H.6. CYLINDRICAL AND TRUSSED LEGS ON THE BETHLEHEM MS-225 SPARTAN 202 AND GUSTO 

MSC CJ70 MAERSK INSPIRER. ......................................................................................... 289

FIGURE H.7. ALTERNATIVE LEG AND CHORD DESIGNS. ............................................................................ 290

FIGURE H.8. RACK CHOCKS ARE INSERTED AGAINST THE LEG’S RACKS TO TRANSFER THE VERTICAL LOAD 

AWAY FROM THE PINIONS. .............................................................................................. 291

FIGURE H.9. MAT FOUNDATION OF A JACKUP RIG. ................................................................................... 292

FIGURE H.10. CANTILEVER DRILLING RIG OPERATING OVER A FIXED PLATFORM. .................................. 293

FIGURE H.11. COMMON U.S. BUILT JACKUP DESIGNS; CLOCKWISE FROM TOP LEFT: LETOURNEAU SUPER 

116E, LETOURNEAU TARZAN, LETOURNEAU 240C, LETOURNEAU SUPER GORILLA 

XL. .................................................................................................................................. 294

FIGURE H.12. HULL DIMENSIONS OF COMMON LETOURNEAU JACKUP DESIGNS. .................................... 295

FIGURE H.13. LETOURNEAU SUPER GORILLA XL SIZE COMPARISON. ..................................................... 296

FIGURE H.14. COMMONLY BUILT INTERNATIONAL JACKUPS; CLOCKWISE FROM UPPER LEFT: KFELS B

CLASS, GUSTO MSC CJ70, PACIFIC CLASS 375, F&G JU 2000E. .................................. 297
xix

FIGURE I.1. WORK PROCESSES IN JACKUP ASSEMBLY. ............................................................................. 301

FIGURE I.2. EARLY CONSTRUCTION STAGES OF JACKUP RIGS: F&G JU 2000E (TOP) AND HANK BOSWELL

(BOTTOM) AT THE LETOURNEAU VICKSBURG, MISSISSIPPI YARD. ................................ 302

FIGURE I.3. STRUCTURAL DESIGN OF A JACKUP HULL. ............................................................................. 303

FIGURE I.4. HULL CONSTRUCTION OF A F&G SUPER M2 RIG (TOP) AND TWO LETOURNEAU SUPER 116S 

AT THE AMFELS BROWNSVILLE, TEXAS YARD. ............................................................ 304

FIGURE I.5. TOPSIDE INSTALLATION ON F&G JU 2000E (LEFT) AND BOB PALMER (RIGHT) AT THE 

LETOURNEAU VICKSBURG, MISSISSIPPI YARD. .............................................................. 305

FIGURE I.6. PRINCIPAL COMPONENTS OF LEG CHORDS. ............................................................................ 306

FIGURE I.7. FORMED HALF CHORDS PRESSED BY JACKRABBIT STEEL. ..................................................... 306

FIGURE I.8. LAUNCHING RIGS AT AMFELS (TOP) AND LETOURNEAU (BOTTOM) SHIPYARDS. ................ 307

FIGURE I.9. CONSTRUCTION OF F&G SUPER M2; TOP SECTION OF LEG INSTALLED. ............................... 308

FIGURE J.1. EXAMPLE SPECIFICATION SHEET FOR SEADRILL’S KFELS B CLASS JACKUP. ...................... 311

FIGURE J.2. INTERACTIONS BETWEEN MAJOR RIG SYSTEMS. .................................................................... 312

FIGURE J.3. DRILLING RIG SYSTEM COMPONENTS. ................................................................................... 313

FIGURE J.4. A DERRICK AND CANTILEVER ON A JACKUP RIG. ................................................................... 314

FIGURE J.5. TOP DRIVE SYSTEM. ............................................................................................................... 315

FIGURE J.6. DRAWWORKS. ........................................................................................................................ 316

FIGURE J.7. DRILLING FLUID CIRCULATION DIAGRAM. ............................................................................ 317

FIGURE J.8. LEWCO MUD PUMP. ................................................................................................................ 318

FIGURE J.9. SHALE SHAKER (TOP) AND HYDROCYCLONE (BOTTOM)........................................................ 319

FIGURE J.10. BOP STACK ON A JACKUP RIG INCLUDING FOUR RAM BOPS AND ONE ANNULAR BOP. ..... 320

FIGURE J.11. SCHEMATIC OF A RAM BOP. ................................................................................................ 321

FIGURE J.12. IRON ROUGHNECK. ............................................................................................................... 322

FIGURE J.13. CATWALK MACHINE. ........................................................................................................... 323

FIGURE J.14. PIPE DECK MACHINE. ........................................................................................................... 324

FIGURE J.15. DRILLING CONTROL STATIONS. ........................................................................................... 325

FIGURE K.1. THE HITACHI 250, LETOURNEAU SUPER 116E, AND GUSTO MSC CJ70 RIGS. .................... 331

FIGURE K.2. DISTRIBUTION OF RIGS IN THE SAMPLE. ............................................................................... 332

FIGURE K.3. RELATIONSHIP BETWEEN WATER DEPTH AND RIG WEIGHT. ................................................. 333

FIGURE K.4. RELATIONSHIP BETWEEN HULL DIMENSIONS AND RIG WEIGHT. .......................................... 334

FIGURE K.5. MODEL RELATIONSHIP BETWEEN WATER DEPTH AND PREDICTED WEIGHT FOR RIGS OF 

DIFFERENT LENGTH AND BREADTH. ................................................................................ 335

FIGURE L.1. DRILLING EQUIPMENT; CLOCKWISE FROM UPPER LEFT; MUD PUMPS, TOP DRIVE, SHALE 

SHAKER, DRAWWORKS. ................................................................................................... 348

FIGURE L.2. LOCATIONS OF MAJOR SUPPLIERS FOR THE JACKUP RIG INDUSTRY IN THE U.S. .................. 349
xx

FIGURE L.3. DISTRIBUTION OF CAPITAL COSTS FOR JACKUP RIG CONSTRUCTION. ................................... 350

FIGURE L.4. BLS PRODUCER PRICE INDICES RELATED TO JACKUP CONSTRUCTION, 2000-2011. ............. 351

FIGURE L.5. JACKUP CONSTRUCTION REVENUE GENERATED BY BROWNSVILLE AND VICKSBURG 

SHIPYARDS, 2002-2012. .................................................................................................. 352

FIGURE M.1. NUMBER AND COST OF WORLDWIDE JACKUP AND FLOATER ORDERS, 2000-2011. ............. 357

FIGURE M.2. DOMESTIC U.S. STEEL PRICES 2000-2011. .......................................................................... 358

FIGURE M.3. ASIAN STEEL INDEX AND AVERAGE WORLD JACKUP PRICES, 2000-2010. ........................... 358

FIGURE M.4. BLS OIL AND GAS FIELD MACHINERY EQUIPMENT PRODUCER PRICE INDEX, 1990-2011. ... 359

FIGURE M.5. RELATIONSHIP BETWEEN THE BLS OIL AND GAS MACHINERY EQUIPMENT INDEX AND 

GLOBAL JACKUP PRICES. ................................................................................................. 359

FIGURE M.6. ANNUAL COMPENSATION IN U.S., KOREAN, AND SINGAPOREAN SHIPYARDS, 2002-2010. 360

FIGURE M.7. PRODUCTIVITY IN THE SHIPBUILDING SECTOR IN THE U.S., KOREA, AND SINGAPORE, 2002-

2010. ............................................................................................................................... 360

FIGURE M.8. REVENUE GENERATED PER U.S. DOLLAR SPENT ON LABOR IN U.S., KOREAN, AND 

SINGAPOREAN SHIPYARDS, 2002-2010. .......................................................................... 361

FIGURE N.1. DISTRIBUTION OF JACKUP AND FLOATER NEWBUILD COSTS. ............................................... 370

FIGURE N.2. DISTRIBUTION OF JACKUP AND FLOATER REPLACEMENT COSTS. ........................................ 371

FIGURE N.3. DISTRIBUTION OF JACKUP, SEMISUBMERSIBLE, AND DRILLSHIP AGES FOR THE 2009 RIG 

FLEET. .............................................................................................................................. 372

FIGURE N.4. RELATIONSHIP BETWEEN WATER DEPTH AND COST IN JACKUP NEWBUILDS. ...................... 373

FIGURE N.5. NEWBUILD COST MODEL A OUTPUT CONTAINING WATER DEPTH AND WATER DEPTH 

SQUARED TERMS. SEE TABLE N.4 FOR MODEL A PARAMETERS. .................................... 373

FIGURE N.6. EFFECTS OF TIME AND MARKET CONDITIONS ON REPLACEMENT COSTS. ............................. 374

FIGURE N.7. JACKUP REPLACEMENT COSTS AS A FUNCTION OF WATER DEPTH. ...................................... 374

FIGURE N.8. REPLACEMENT COSTS OF SEMISUBMERSIBLES AND DRILLSHIPS AS A FUNCTION OF WATER 

DEPTH. ............................................................................................................................. 375

FIGURE N.9. REPLACEMENT COSTS OF DRILLSHIPS AS A FUNCTION OF DELIVERY YEAR. ........................ 375
xxi 

LIST OF TABLES 

TABLE A.1. ENVIRONMENTAL CRITERIA USED IN RIG DESIGN BY OFFSHORE REGION........................... 149

TABLE A.2. JACKUP SPECIFICATION COMPARISON FOR STANDARD AND HIGH-SPEC UNITS ROWAN 

JUNEAU VS. ROWAN EXL III............................................................................................. 149

TABLE A.3. ADVANTAGES AND DISADVANTAGES OF STATION KEEPING SYSTEMS ................................ 149

TABLE A.4. DISPLACEMENT AND SIZE OF MODERN SEMISUBMERSIBLE DESIGNS .................................. 150

TABLE A.5. SEMISUBMERSIBLE RIG GENERATIONS AND TECHNOLOGY DEVELOPMENT ........................ 150

TABLE A.6. TYPICAL SEMISUBMERSIBLE SPECIFICATIONS BY GENERATION .......................................... 150

TABLE A.7. SPECIFICATIONS OF MODERN DRILLSHIPS ............................................................................ 151

TABLE A.8. COSTS OF RIGS UNDER CONSTRUCTION IN 2012 IN MILLION DOLLARS............................... 151

TABLE A.9. REPLACEMENT COSTS OF SELECTED RIGS IN 2012 ............................................................... 151

TABLE B.1. DISTRIBUTION OF RIGS BY CLASS AND OPERATOR INCLUDING COLD-STACKED RIGS AND 

RIGS UNDER CONSTRUCTION IN THE 1Q 2011 ............................................................... 179

TABLE B.2. GEOGRAPHIC DISTRIBUTION OF ACTIVE RIGS BY NATION IN 2011 ...................................... 180

TABLE B.3. CONTRACT DRILLING SERVICE MARKET SIZE IN 2010 ......................................................... 181

TABLE B.4. E&P FIRM INVESTMENT IN CONTRACT DRILLING SERVICES BY REGION IN 2010................ 181

TABLE B.5. NUMBER OF NEWBUILD RIGS ON ORDER BY SHIPYARD IN 2011 .......................................... 182

TABLE B.6. WORLDWIDE DISTRIBUTION OF MODU CONSTRUCTION IN 2011 ........................................ 182

TABLE B.7. NUMBER OF RIGS UPGRADED IN 2009 AND 2010 BY SHIPYARD ........................................... 183

TABLE B.8. EXAMPLES OF JACKUP RIG UPGRADE CONTRACTS............................................................... 184

TABLE B.9. EXAMPLES OF SEMISUBMERSIBLE RIG UPGRADE CONTRACTS............................................. 185

TABLE B.10. EXAMPLES OF DRILLSHIP UPGRADE CONTRACTS ............................................................... 186

TABLE B.11. NUMBER OF MAJOR UPGRADES BY YEAR AND ESTIMATED MARKET VALUE, 2001-2010 . 186

TABLE B.12. NUMBER OF TRANSACTIONS IN THE SECONDHAND MARKET BY FIRM, 2005-2010 ............ 187

TABLE B.13. AVERAGE AND RANGE OF PRICES IN THE SECONDHAND MARKET, 2005-2010 .................. 187

TABLE B.14. TRANSACTIONS AND MARKET VALUATION IN THE SECONDHAND MARKET, 2005-2010 ... 188

TABLE C.1. DISTRIBUTION OF ACTIVE RIGS BY NATION IN 2011 ............................................................. 199

TABLE C.2. MAJOR FEATURES OF OFFSHORE REGIONS ........................................................................... 200

TABLE C.3. AVERAGE WATER DEPTH OF RIG CONTRACTS, 2000-2010................................................... 201

TABLE C.4. ACTIVE AND READY-STACKED RIGS BY MARKET IN 2011 ................................................... 202

TABLE C.5. RELATIONSHIPS BETWEEN THE NUMBER OF ACTIVE AND CONTRACTED RIGS, 1999-2011 .. 202

TABLE C.6. AVERAGE UTILIZATION RATES BY REGION, 2000-2010 ....................................................... 203

TABLE C.7. JACKUP UTILIZATION REGIONAL CORRELATION MATRIX, 2000-2010 ................................. 203
xxii 

TABLE C.8. FLOATER UTILIZATION REGIONAL CORRELATION MATRIX, 2000-2010 .............................. 203

TABLE C.9. AVERAGE DAYRATES BY REGION BETWEEN 2000-2006 AND 2006-2010 ............................. 204

TABLE C.10. JACKUP DAYRATE REGIONAL CORRELATION MATRIX, 2000-2010 .................................... 204

TABLE C.11. FLOATER DAYRATE REGIONAL CORRELATION MATRIX, 2000-2010 .................................. 204

TABLE C.12. QUARTERLY VOLATILITY IN THE SHALLOW AND DEEPWATER MARKETS, 2000-2010 ...... 205

TABLE C.13. CONTRACT TYPE BY RIG MARKET AND REGION, 2000-2010 .............................................. 205

TABLE C.14. AVERAGE CONTRACT DURATION IN DAYS, 2000-2010 ...................................................... 205

TABLE C.15. LARGEST E&P CUSTOMERS BY REGION, 2000-2010 ........................................................... 206

TABLE D.1. THE LARGEST PUBLICLY TRADED DRILLING CONTRACTORS IN 2011 .................................. 225

TABLE D.2. THE LARGEST STATE-OWNED DRILLING CONTRACTORS IN 2011 ........................................ 226

TABLE D.3. SELECTED PRIVATELY HELD DRILLING CONTRACTORS IN 2011 .......................................... 227

TABLE D.4. ENTERPRISE VALUE OF SELECTED DRILLING CONTRACTORS AS A PERCENT OF FLEET VALUE,

2010-2012 ....................................................................................................................... 227

TABLE D.5. SPECIALIZATIONS AND BUSINESS STRATEGIES OF SELECTED FIRMS IN 2011 ...................... 228

TABLE D.6. FOUR LARGEST FIRMS BY NUMBER OF ACTIVE RIGS PER REGION AND WATER DEPTH 

CATEGORY IN 2011 ......................................................................................................... 229

TABLE D.7. DRILLING CONTRACTOR REVENUES IN MILLION U.S. DOLLARS BY REGION IN 2011.......... 230

TABLE D.8. MAJOR E&P CUSTOMERS OF SELECTED DRILLING CONTRACTORS IN 2011 ........................ 230

TABLE D.9. TRANSOCEAN AND DIAMOND PERFORMANCE STATISTICS BY MARKET SEGMENT IN 2011 . 231

TABLE D.10. MARKET CONCENTRATION METRICS OF THE WORLD MODU FLEET IN 2010 ................... 232

TABLE E.1. OFFSHORE DRILLING CONTRACTS BY REGION, 2000-2010 ................................................... 245

TABLE E.2. AVERAGE DAYRATES BY REGION BETWEEN 2000-2006 AND 2006-2010 ............................. 245

TABLE E.3. MODELS OF THE RELATIONSHIP BETWEEN UTILIZATION RATES AND DAYRATES, 2006- 

2010 ................................................................................................................................ 246

TABLE E.4. RELATIONSHIP BETWEEN MAXIMUM DRILLING DEPTH AND DAYRATES, 2000-2010 ........... 246

TABLE E.5. RELATIONSHIP BETWEEN MAXIMUM WATER DEPTH AND DAYRATES, 2000-2010 .............. 247

TABLE E.6. RIG SPECIFICATIONS AND AVERAGE DAYRATES, 2000-2010................................................ 247

TABLE E.7. EFFECTS OF RIG SPECIFICATION ON DAYRATES BY REGION, 2000-2010 .............................. 248

TABLE E.8. PREMIUM ASSOCIATED WITH HIGH SPECIFICATION RIGS, 2000-2010 .................................. 248

TABLE E.9. INFLUENCE OF CONTRACT DURATION ON DAYRATES IN THE JACKUP AND FLOATER 

MARKETS, 2000-2010 ..................................................................................................... 249

TABLE E.10. AVERAGE DAYRATES BY E&P FIRM CLASSIFICATION, 2000-2010 ..................................... 249

TABLE E.11. MODELS OF THE RELATIONSHIP BETWEEN DAYRATES AND E&P FIRM OWNERSHIP, 2000-

2010 ................................................................................................................................ 250

TABLE E.12. AVERAGE FLOATER DAYRATES BY WELL TYPE, 2000-2010 .............................................. 250

TABLE F.1. NPV NEWBUILD MODEL VARIABLE DEFINITIONS ................................................................ 257
xxiii 

TABLE F.2. OPTIMISTIC AND EXPECTED PARAMETERIZATIONS OF THE NEWBUILDING MODEL ............. 258

TABLE F.3. STACKED AND ACTIVE OPERATING EXPENDITURES FOR JACKUPS AND FLOATERS, 2010- 

2011 ................................................................................................................................ 259

TABLE F.4. PERCENTAGE EFFECTS OF A 1% CHANGE IN SELECTED VARIABLES ON THE BREAK-EVEN 

DAYRATE ........................................................................................................................ 259

TABLE F.5. STACKING MODEL VARIABLE DEFINITIONS .......................................................................... 260

TABLE F.6. NET ASSET VALUES OF RIG CLASSES, 4Q 2011..................................................................... 260

TABLE F.7. PARAMETERIZATION OF THE NAV MODEL............................................................................ 261

TABLE F.8. COMPARISON OF NAV ESTIMATES FOR TWO STANDARD 300 FT JACKUP RIGS IN JANUARY 

2012 ................................................................................................................................ 261

TABLE G.1. WORLDWIDE DISTRIBUTION OF RIG CONSTRUCTION IN 2012 .............................................. 271

TABLE G.2. SHIPYARD DELIVERIES FROM 2005-2012 AND 2011 MARKET CAPITALIZATION.................. 271

TABLE G.3. JACKUP CONSTRUCTION IN U.S. SHIPYARDS, 2000-2012 ..................................................... 272

TABLE G.4. DELIVERIES OF SEMISUBMERSIBLES FROM U.S. SHIPYARDS, 2000-2012 ............................. 273

TABLE G.5. NUMBER OF NEWBUILD (2005-2012) RIGS IN THE FLEETS OF SELECTED DRILLING 

CONTRACTORS IN 2012 ................................................................................................... 273

TABLE H.1. NUMBER OF RIGS DELIVERED AND UNDER CONSTRUCTION WORLDWIDE BY DESIGN CLASS,

1Q 2012 ........................................................................................................................... 283

TABLE H.2. CHARACTERISTICS OF SELECTED GUSTO MSC JACKUPS...................................................... 283

TABLE H.3. JACKUP RIGS DELIVERED FROM U.S. YARDS BETWEEN 2000-2012 ..................................... 284

TABLE H.4. CHARACTERISTICS OF COMMONLY BUILT JACKUP RIGS ...................................................... 284

TABLE K.1. LEG WEIGHTS OF ALTERNATIVE RIG DESIGNS ..................................................................... 329

TABLE K.2. JACKUP RIG LIGHTSHIP DISPLACEMENTS ............................................................................. 330

TABLE L.1. MARKET SHARE (IN PERCENT) OF RIG EQUIPMENT SUPPLIERS IN U.S. JACKUP RIG 

CONSTRUCTION, 2000-2010 ............................................................................................ 339

TABLE L.2. RIG CONSTRUCTION COST ESTIMATION MODULES............................................................... 339

TABLE L.3. CONSTRUCTION COSTS OF U.S. JACKUP RIGS, 1996-2011 .................................................... 340

TABLE L.4. AVERAGE COST OF JACKUP RIGS BUILT IN THE U.S. BY WATER DEPTH AND CLASS, 1996-

2011 ................................................................................................................................ 341

TABLE L.5. COST OF LABOR AT U.S. SHIPYARDS, 2002-2009 .................................................................. 342

TABLE L.6. LABOR REQUIREMENTS PER UNIT OF SHIPMENT VALUE, 2002-2009 .................................... 342

TABLE L.7. WEIGHT DISTRIBUTION OF SELECTED JACKUPS .................................................................... 343

TABLE L.8. STEEL GRADE DISTRIBUTION OF A 300 FT MODERATE ENVIRONMENT JACKUP................... 343

TABLE L.9. INSTALLED POWER OF SELECTED JACKUP RIG DESIGNS....................................................... 343

TABLE L.10. LETOURNEAU SUPER 116E RIG KIT COSTS......................................................................... 344

TABLE L.11. CONTRACT COSTS OF JACKUP DRILLING EQUIPMENT......................................................... 344

TABLE L.12. COSTS OF SELECTED JACKUP RIG DRILLING EQUIPMENT IN 2010 ...................................... 345
xxiv 

TABLE L.13. LABOR COST ESTIMATES FOR A HYPOTHETICAL LETOURNEAU SUPER 116E JACKUP IN 

MILLION U.S. DOLLARS.................................................................................................. 345

TABLE L.14. STEEL COSTS FOR A HYPOTHETICAL LETOURNEAU SUPER 116E JACKUP.......................... 345

TABLE L.15. DISTRIBUTION OF CONSTRUCTION COSTS FOR A HYPOTHETICAL LETOURNEAU SUPER 

116E................................................................................................................................ 346

TABLE L.16. JACKUP DRILLING RIG MARKET REVENUE IN MILLION U.S. DOLLARS.............................. 346

TABLE L.17. ESTIMATED EMPLOYMENT IN THE U.S. JACKUP RIG CONSTRUCTION INDUSTRY............... 347

TABLE L.18. JACKUP RELATED FULL TIME EQUIVALENT EMPLOYMENT ................................................ 347

TABLE M.1. CONSTRUCTION COST DISTRIBUTION FOR JACKUPS AND FLOATERS................................... 355

TABLE M.2. JACKUP DESIGN CLASS PROPERTIES AND NEWBUILD COST IN 2011 ................................... 355

TABLE M.3. SEMISUBMERSIBLE DESIGN CLASS PROPERTIES AND NEWBUILD COST IN 2011 ................. 356

TABLE M.4. DRILLSHIP DESIGN CLASS PROPERTIES AND NEWBUILD COST IN 2011 ............................... 356

TABLE N.1. NEWBUILD AND REPLACEMENT COST AND SELECTED SAMPLE STATISTICS IN 2009 ........... 365

TABLE N.2. NEWBUILD JACKUP AND SEMISUBMERSIBLE AVERAGE COSTS BY WATER DEPTH AND 

ENVIRONMENTAL DESIGN CONDITIONS IN 2009 ............................................................ 365

TABLE N.3. NEWBUILD COSTS BY COUNTRY OF SHIPYARD IN MILLION U.S. DOLLARS IN 2009 ............ 366

TABLE N.4. MODELS OF JACKUP NEWBUILD COSTS ................................................................................ 367

TABLE N.5. MODELS OF SEMISUBMERSIBLE NEWBUILD COSTS .............................................................. 368

TABLE N.6. JACKUP NEWBUILD COSTS BY DESIGN CLASS ...................................................................... 368

TABLE N.7. JACKUP REPLACEMENT COST MODELS................................................................................. 368

TABLE N.8. SEMISUBMERSIBLE REPLACEMENT COST MODELS............................................................... 369

TABLE N.9. DRILLSHIP REPLACEMENT COST MODELS ............................................................................ 369
1

EXECUTIVE SUMMARY 

Mobile offshore drilling units (MODUs) are marine vessels that drill holes in the earth to find 

and produce hydrocarbons. Offshore drilling occurs throughout the world wherever hydrocarbon 

potential exists. Since 1950, over 120,000 wells have been drilled offshore, with about half in the 

U.S. Gulf of Mexico. Over the past decade, about 3,500 offshore wells were drilled each year. In 

2010, revenues to drilling contractors were approximately $45 billion. MODUs consist of an 

ocean-going vessel with all of the systems required to support drilling, and are composed of 

jackups, semisubmersibles, and drillships. Currently, offshore oil represents approximately onethird of global production, and as offshore production increases in importance, MODUs will 

continue to play a critical role in bringing supply to market. The technological capabilities of 

MODUs define the boundaries of offshore exploration and production. 

In this report, we survey the MODU industry and contract drilling market, and focus on 

newbuilding in the Gulf of Mexico. The report is organized in four sections. Chapters 1 and 2 

provide background information. Chapters 3 through 6 characterize the industry sector and the 

contract drilling service market. Chapters 7 through 11 discuss the newbuild market with an 

emphasis on jackup construction, and Chapters 12 through 14 analyze the economic impacts of 

the newbuild market in the U.S. and construction cost functions. 

Chapter 1 describes the primary types of rigs employed in the industry and defines the 

activity states over a rig’s life. In Chapter 2, the five markets that make up the MODU industry 

are described. These markets include the newbuild market where rigs are built, the contract 

drilling market where rigs are leased, the secondhand market where rigs are sold, the upgrade 

and maintenance market in which rigs are upgraded and maintained for service, and the scrap 

market where rigs are dismantled and sold for scrap steel. The newbuild and contract drilling 

markets are the largest and most transparent sectors and are the focus of this report. 

Chapters 3 and 4 introduce the contract drilling market. In Chapter 3, the geographic 

distribution, utilization and dayrate trends of rigs are presented on a regional and global basis, 

and the different types of contracts employed are outlined. In Chapter 4, the industrial 

organization and market structure of the contract drilling industry is described. Firms diversify 

by region, rig class, and rig quality, and specialization has impacts on dayrates and utilization. 

Consolidation has been a major characteristic of the industry, and in 2012, the contract drilling 

market is dominated by five publicly traded firms: Transocean, Noble Drilling, ENSCO, 

Diamond Offshore and Seadrill. The contract drilling industry provides similar services (drilling 

wells) using commodity-like units (rigs), and despite many years of consolidation, the industry is 

still highly competitive. Demand for drilling services is dynamic, and over the past decade, 

growth has occurred most notably in the Persian Gulf and Brazil. 

In Chapter 5, we analyze the factors that impact MODU dayrates. Oil price explains large 

proportions of the variation in the number of active rigs and average dayrates between 2000 and 

2010. Utilization is a weaker predictor of dayrates with effects varying by region and time 

period. Rig specifications are also shown to impact dayrates. State-owned oil companies pay 

higher dayrates than private oil companies which suggests that state-owned and private oil 

companies have different motivations for investing in drilling or have different negotiation 
2

strategies. Appraisal drilling is associated with higher dayrates than exploratory or 

developmental drilling. 

In Chapter 6, we develop conceptual models of firm stacking and newbuild decision-making. 

A net present value model of newbuilding indicates that relatively high combinations of dayrates 

and utilization are required to justify investment in jackups. We build a model of stacking costs 

and show why operating a rig may be preferred over stacking even if operating expenses exceed 

the dayrate. We describe and illustrate the methods used by investment firms for calculating the 

net asset value of a rig. 

Chapter 7 describes the newbuild market with emphasis on the U.S. From the early 1980s 

through the late 1990s, few rigs were delivered worldwide. By 2004, drilling contractors began 

to order new jackup rigs to replace the aging fleet which began the first major newbuilding cycle 

since the early 1980s. New orders stopped in 2008 following the global economic recession and 

decline in oil prices, and resumed in late 2010. The newbuild industry is concentrated in Asia, 

and the U.S. represents only a small fraction of the global market focused exclusively on 

jackups. The U.S. newbuild industry consists of two shipyards: the LeTourneau shipyard in 

Vicksburg, Mississippi and the Keppel AmFELS shipyard in Brownsville, Texas. Keppel 

AmFELS has work scheduled through 2013. The LeTourneau shipyard was sold twice in 2011, 

and, barring a major change in the market, is unlikely to deliver additional rigs in the future. U.S. 

yards are unlikely to win contracts for jackups employed outside the region due to competition 

and transport costs. 

In Chapters 8 through 11, technical aspects of rig design and construction are presented. 

Chapter 8 defines the structural components of jackup rigs and describes the process of 

construction and the designs most frequently built in the U.S. Chapter 9 provides a non-technical 

introduction to the tradeoffs that occur in jackup design, and in Chapter 10, we present a pictorial 

summary of the most common drilling equipment and systems. Jackup rig displacement is 

generally considered proprietary but is an important determinant of construction cost since it 

influences material and labor requirements. In Chapter 11, a regression model of jackup rig 

weights using water depth capability and length and breadth of the hull as explanatory variables 

is constructed. 

Chapter 12 analyzes the construction costs of jackup rigs built in the U.S using twenty-five 

jackup rigs ordered from U.S. yards between 1997 and 2007. The total value of U.S. rig 

deliveries peaked in 2008 at $1 billion and maintained an average of $700 million per year 

during the period. Since the 2008 peak, the U.S. newbuild industry has declined, and barring a 

major change in market conditions, future activity is expected to remain low. Labor and drilling 

equipment are the largest cost components of rig construction and account for over half of the 

total cost of a rig. Labor costs have been relatively stable over the past decade and drilling 

equipment costs depend on equipment specifications. The hull and superstructure steel make up a 

small fraction of the total costs of a rig (<5%), but the leg steel, which is often sold as part of a 

“rig kit”, is a significant component (≈20%). 

Chapter 13 discusses the factors that influence newbuild capital expenditures and 

replacement costs. A number of factors impact costs including market conditions, design class, 
3

vessel weight, water depth capability, rig age, upgrade status, environmental characteristics, 

contract structure, construction shipyard, and rig specifications. Steel and equipment cost indices 

are reasonable predictors of newbuild costs. 

Chapter 14 evaluates the newbuild and replacement costs of jackups, semisubmersibles, and 

drillships using empirical data for a representative sample of inventory. Cost models provide 

insight into market drivers and are used by investors, government agencies, and other 

stakeholders to evaluate newbuild programs. Replacement cost models are used to evaluate the 

value and insurance liability of an existing fleet or asset. The average jackup rig for orders 

placed during the 2005 to 2008 newbuild cycle cost $225 million, while drillships cost more than 

semis with average costs of $672 and $553 million, respectively. Water depth was the single best 

predictor of rig cost and replacement cost models explained larger proportions of variance than 

newbuild models which is likely due to the manner in which cost estimates were performed. For 

jackups, newbuild costs exhibited a nonlinear relationship between costs and water depth, while 

nation of construction did not add predictive power to the models suggesting that nations are able 

to compensate for high labor costs. For semis, delivery year was a significant predictor 

suggesting that costs increased over the newbuilding cycle. 
5

1. MOBILE OFFSHORE DRILLING UNITS 

Mobile offshore drilling units (MODUs or rigs) are ocean-going vessels used to drill, 

complete and workover wellbores in marine environments. The fleet has grown and evolved over 

time as more production comes from offshore and operators move into deeper water and more 

challenging environments targeting more complex and harder to find reservoirs. The fleet that 

exists today consists of both old and new technology and includes a variety of vessel classes built 

to various specifications. The purpose of this chapter is to describe MODU classifications and 

introduce the technical factors that characterize rigs. The chapter includes a description of the 

function of rigs, the manner in which rigs are categorized, the main rig classes, and the activity 

states through which a rig transitions over its lifecycle. We conclude with a description of the 

newbuild and replacement cost of rigs. 

1.1. MODU FUNCTION

1.1.1. Well Type 

Wells are drilled for exploration, appraisal or production. Exploration wells are used to find 

and confirm the presence of hydrocarbons, appraisal wells delineate and define the boundaries of 

the reservoir, and development wells are used for production. Development drilling differs from 

exploration and appraisal drilling in that data acquisition is no longer the primary function of the 

well. In development drilling, the objective is to drill targets as efficiently as possible. MODUs 

are used for all well types, but are the only economic option for exploration and appraisal 

drilling, before offshore infrastructure is installed. Development wells may be drilled from 

MODUs or fixed or floating platforms. 

1.1.2. Drilling a Well 

During drilling, the rig bores a hole in the earth using a drillbit which is connected to and 

turned by a drillpipe. Drilling fluid passes down the drillpipe through the bit where it lubricates 

the bit and controls hydrostatic pressure inside the well. The drilling fluid carries cuttings back 

up to the rig through the annulus between the drillpipe and the borehole. Wells are drilled in 

stages and when the bottom of a stage is reached, the open-hole is cased off using steel pipe to 

prevent the hole from collapsing on the drillpipe. Offshore wells usually have three to four 

casing strings before reaching the target formation (Figure A.1). 

1.1.3. Completions and Workovers 

A well will be completed immediately if it is a development well, while for exploratory 

wells, completion activity will await field delineation and additional planning. During 

completion, production casing is set across the reservoir interval and the blowout preventer is 

removed and replaced with a dry tree or subsea wellhead. Production tubing is suspended from 

the wellhead and a packer is used to isolate the annulus. Finally, the production casing is 

perforated to make contact with the reservoir, and if necessary, the well is stimulated and 

fractured. 
6

A workover the repair or stimulation of an existing production well intended to restore, 

enhance, or prolong production. In many cases, a workover entails the removal and replacement 

of production tubing after the well has been killed. A rig is required for workovers, but a smaller 

specialized workover rig may be used. 

1.1.4. Well Configuration 

Wells may be vertical, directional or horizontal (Figure A.2), and all types are used offshore. 

In some cases, branches spurred off from a single well (sidetracks) may be drilled to target 

different areas of a reservoir. Exploration wells are almost always drilled vertically with the 

target directly below the rig. Most developmental wells are drilled directionally because several 

wells targeting different zones may be drilled from a central location, or the target lies under salt 

or an environmentally sensitive area. Long horizontal sections may be required to tap thin beds 

far from the rig or heavy oils that require greater contact with the reservoir. Figure A.3 shows the 

depth and geology of recent offshore wells in the Gulf of Mexico (GOM). 

1.1.5. Well Depth, Pressure, and Temperature 

The total (or measured) depth of a well is measured along the wellbore while true vertical 

depth is measured straight down to the target. Both temperature and pressure increase with depth. 

The temperature gradient averages 2° F/100 ft (3.6° C/100 m) and varies between 0.5 to 5 

°F/100ft (1 to 9° C/100 m) worldwide. The pressure on the rock is called geostatic or lithostatic 

pressure and increases at an average rate of 100 psi/100 ft. The pressure on the fluids in the pores 

of the rock is reservoir or fluid pressure, and depends on the density of the overlying water; 

average fluid pressure worldwide is 45 psi/100ft (Hyne, 2001). 

High pressures and temperatures (above 300° F and 0.8 psi/ft) are common in deep (>15,000 

ft) and ultradeep (>25,000 ft) wells (Lyons et al., 2008). Wells are classified into high pressurehigh temperature (HPHT), ultra-HPHT and HPHT-hc (hors categorie or beyond categorization) 

categories (Figure A.4) based on technological thresholds associated with the elastomeric seals 

and electronic equipment used in downhole tools (Belani and Orr, 2008). Figure A.5 shows the 

geographic distribution of HPHT activity in 2008. HPHT wells stress many rig components and 

are more difficult to control relative to normal wells. Equipment and systems must be certified to 

operate at elevated temperatures and pressures. Upgraded equipment includes blowout 

preventers rated at 10,000 to 15,000 psi, enhanced mud systems including mud cooling, glycol 

injection units, high pressure choke and kill lines, pressure and temperature sensors, and high 

pressure risers. 

1.2. RIG CLASSIFICATION

Rigs are classified according to type (bottom supported, floating), environmental capacity 

(harsh, moderate), water depth, and specification (standard, premium). 

1.2.1. Rig Type 

MODUs are classified as bottom supported and floating rigs. In bottom-supported units, the 

rig is in contact with the seafloor during drilling, while a floating rig floats over the site while it 

drills, held in position by anchors or equipped with thrusters using dynamic positioning (Figure 

A.6).
7

Bottom-supported units include barges, submersibles and jackups and are used for protected 

and shallow-water drilling (Figure A.7). Drilling barges are floating vessels that rest on the 

bottom while drilling. They are limited to approximately 30 ft water depths and are only used for 

inland areas such as Lake Maracaibo or the Mississippi River delta. Submersibles consist of a 

deck supported by pontoons; during operation, the pontoons are flooded and the vessel rests on 

the bottom; they are rarely used today. A jackup is a barge with legs that can be adjusted to suit a 

given location. Once in position, the legs are lowered, hoisting the drilling platform above the 

water. Jackups are the most commonly used offshore drilling rig in the world and are capable of 

drilling on a wide variety of tracks in water depths up to 500 ft. Jackups can only work in water 

depths that are less than the length of its legs and the required air gap and surface penetration at 

location. When moving between drilling locations, the hull is usually towed by tugs or carried by 

a specialist vessel, with the legs sticking high into the air. 

Floating units include semisubmersibles and drillships and are used for deepwater (> 500 ft) 

drilling (Figure A.8). Floaters can operate in deeper water than bottom-supported units since no 

physical connection between the rig and the seafloor is required. Floaters are essentially ships 

with drilling equipment and are usually self-propelled and have a marine crew. Motion 

compensation systems are an essential element of all floating rigs to ensure that drilling can be 

performed with the vertical heave of the rig. 

The semisubmersible (semi) consists of a deck supported by submerged pontoons connected 

by several large columns. By varying the amount of ballast in the pontoons, the unit can be 

raised or lowered; the lower the pontoons lie beneath the surface, the less they are affected by 

wave and current action. Semisubmersibles are very stable in harsh environments and most 

deepwater, harsh environment rigs are semisubmersibles. 

A drillship is a self-propelled ship-shaped vessel. The rig derrick is usually mounted in the 

middle of the vessel and drilling is conducted through a large aperture known as a “moon pool.”

Drillships are the most advanced and expensive sector of the rig market and many water depth 

records are held by drillships. New drillships are capable of drilling in 12,000 ft of water with 

wells up to 40,000 ft deep. 

Jackups, drillships and semisubmersibles comprise the majority of the modern offshore fleet, 

and while other marine drilling systems exist,1 all other systems are of either limited mobility or 

are not capable of drilling in offshore locations. 

1.2.2. Environmental Capacity 

Rigs are classified as harsh or moderate environment units. Harsh environments are 

characterized by frequent and severe storms as occur during winter in the North Sea, Norwegian 

 

1

 For example, drilling tenders are barge or semi-submersible hulls that transport drilling and support 

equipment. Once onsite, the drilling tender transfers drilling equipment onto the platform while all other systems 

remain on the tender. While tenders are capable of working offshore, they are not capable of drilling on their own 

and are only used for developmental drilling. 
8

Sea, North Pacific, Eastern Canada and Arctic Ocean. Figure A.9 shows average wind speeds 10 

m above the ocean surface in February and July, corresponding to winter in the Northern and 

Southern hemispheres, respectively. In the GOM and much of Asia, moderate environmental 

conditions predominate but tropical storms may cause severe weather events. In Brazil, West 

Africa and the Persian Gulf, severe weather is rare. 

In order to work efficiently in a region, a rig must be capable of operating during average one 

year storm conditions and surviving 100 year storm conditions (Eikill and Oftedal, 2007). Due to 

tropical storms, the 100 year storm conditions in the North Sea are similar to conditions in the 

GOM and Asia; however, one year storm conditions are far more severe in the North Sea (Table 

A.1). As a result, harsh and moderate environment rigs differ in maximum operating conditions, 

but do not differ in maximum survival conditions. 

Harsh environment units have a number of design modifications to decrease weather related 

downtime, including increased variable load to reduce the need for resupply, increased airgap to 

increase wave clearance, increased automation, changes in the geometry of the legs or columns 

to decrease wind and wave loads, and greater spacing between the legs or columns. Harsh 

environment rigs are larger, heavier and more expensive to construct than moderate units (Figure 

A.10).

1.2.3. Water Depth 

Rigs are defined in terms of their maximum water depth capability and are classified into 

water depth classes. Jackups are usually delineated into water depth categories <250, 250-350 

and >350 ft, but other classifications may be employed. Floaters are typically divided into 

midwater (3,000-4,500 ft), deep (<7,500 ft) and ultradeep (>7,500 ft) categories. Water depth 

capabilities are frequently related to rig specifications and age. 

1.2.4. Specification 

High-spec (premium) rigs typically have more powerful mud pumps, a higher hook load and 

a greater variable load than standard rigs, but as with all classifications, definitions vary by firm. 

Generally speaking, a rig is considered high-spec if it can drill in deeper water than other rigs of 

its class, operate in harsh environments or drill HPHT wells. Rowan, for example, defines a 

high-spec jackup as any rig with a hook load greater than 2 million pounds. In most cases, a 

jackup capable of drilling in >350 ft would be high-spec while a jackup limited to <300 ft would 

be considered standard; for floaters, the demarcation between high and low spec occurs at 

approximately 5,000 ft. Table A.2 and Figures A.11(a and b) contrast a standard and high-spec 

jackup. The difference in replacement cost between two units is a measure of the capital 

expenditures required for the improvement in performance. 

1.3. JACKUPS

1.3.1. Design Elements 

Jackups are composed of a triangular box hull approximately 20 to 30 ft high supported by 

three or more legs. The hull contains all of the equipment required to operate the rig and provides 

displacement in the afloat condition. Legs support the weight of the jackup and provide lateral 

stability when elevated. The legs are generally trussed and are composed of three or four vertical 
9

chords running its entire length and connected by a lattice-work of tubular braces. The legs are 

raised and lowered by electro-mechanical rack and pinion jacking systems. The pinions are 

contained in the jacking mechanism and interact with racks on the leg chords (Figure A.12). 

1.3.2. Independent vs. Mat 

Foundations for jackups are classified as independent-leg spudcans or mats. Independent-leg 

jackups have legs that can be jacked up independently of each other and are attached to a 

spudcan footing. Spudcans (Figure A.13) are designed to penetrate the seafloor and transfer 

vertical loads from the legs to the ground; spudcan penetration also provides resistance to lateral 

forces acting on the legs. Mats (Figure A.14) are a rigid plate structure which connects to the 

bottom of each leg. Mat supported rigs are employed where the bottom conditions would cause 

spud cans to over-penetrate the seabed, as with soft muddy soil near the mouths of large rivers, 

or under-penetrate the seabed as with hard rock substrate. Independent-leg jackup dayrates are 

usually priced at a premium to mat jackups because they are in greater demand and have greater 

operational flexibility. 

1.3.3. Cantilevered vs. Slot 

The drilling rig on a jackup can be cantilevered or slot. A cantilevered jackup mounts the rig 

on cantilevers that extend outward from the hull of the unit. A slot jackup mounts the drilling 

unit over a slot in the deck. Cantilever designs are more versatile than slot designs since they can 

be used to drill and workover wells on fixed platforms (Figure A.15) and to drill closely spaced 

wells without repositioning the rig. All rigs built over the past decade have been cantilevered but 

slot jackups are common in the legacy fleet. 

1.4. SEMISUBMERSIBLES

1.4.1. Station Keeping 

Semis are held in position by anchors or are dynamically positioned (Banon et al., 2007). In 

dynamic positioning propellers (thrusters) are mounted on the vessel’s hull below the waterline. 

Satellite positioning, wind sensors and hydrophones send information about wind, waves, and 

current to an on-board computer to maintain position. Dynamic positioning significantly 

increases fuel costs but decreases spread costs, and has been reported under most fuel and 

dayrate price combinations to lead to an operational cost reduction (Klaoudatos, 2006), but we 

are not aware of any empirical studies that support this claim. Table A.3 summarizes the 

advantages and disadvantages of dynamic positioning and other station keeping systems. 

1.4.2. Motion Compensation 

Floating rigs require motion compensation systems to correct for vertical movement of the 

rig due to waves. Two separate motion compensation systems are required to control the tension 

on the marine riser2 and the drill string. A drill string compensator (DSC) keeps the drillbit on 

the bottom of the hole and within the weight limits established by the driller while a riser 

 

2 The riser is the pipe that passes from the rig to the blowout preventer on the seafloor and is used as a conduit 

for the drillpipe, drilling fluids, casing, etc. 
10

tensioner is used to maintain the tension on the drilling riser; both systems utilize pneumatic 

cylinders to push or pull the drill string or riser up or down relative to the rig. 

A DSC is composed of a pneumatic cylinder placed between the travelling block and the 

hook and connected to an air pressure system placed on the deck (Figure A.16). As the rig 

heaves upward, a working fluid flows out of the compensator cylinder; this allows the rod inside 

the cylinder to fall, moving the hook downward relative to the drill floor, but keeping it at a 

constant level relative to the earth. As the rig heaves downward, air flows from the pressure 

vessels to the cylinder, forcing the rod inside the cylinder and the attached hook upward relative 

to the drill floor. A riser tensioner is composed of several hydraulic cylinders with wire line 

sheaves at both ends and operates in the same basic fashion. 

1.4.3. Displacement 

A vessel’s displacement is a measure of its weight, and for most vessels, an empty (lightship) 

and loaded (loadline) displacement is used to estimate the weight and capacity of a vessel. By 

contrast, semisubmersibles are designed to have variable displacements and a significant portion 

of their operating displacement is composed of ballast water. As a result, semi displacements are 

not as closely related to the weight of the vessel. Semis are specified by their transit operating 

and survival displacements; the transit displacement is approximately 75% of the operating 

displacement and survival displacement is intermediate (Halkyard, 2005). 

The operating displacement and size-related measures of modern semisubmersibles are 

shown in Table A.4. There is significant variation in size with the smallest rig (the Gusto DSS 

20) approximately half the displacement of the largest (the Aker H-6e). The Gusto MSC DSS 20 

is designed for the Caspian Sea while the Aker H-6e and GVA 7500 are designed for the North 

Sea environment. 

1.4.4. Generations 

Semisubmersibles are classified into generations based on the year of construction and the 

technology of equipment, environmental specification, variable deck load and water depth 

capability (Tables A.5 and A.6; Figure A.17). As with all rig classifications, the delineation is 

approximate and is meant to serve as a general guideline for categorization and reporting. 

Variable deck load comprises all the weight beyond the lightship and ballast to be carried by the 

vessel. 

First and Second Generation 

The first generation of semis was built between 1962 and 1969 and was generally limited to 

water depths less than 800 feet. During this period, there were significant differences in the 

structural designs of vessels as the technology matured. Notable designs include the SEDCO 135 

(Figure A.18) and ODECO designs. Second generation semis were built between 1970-1981 for 

water depth up to 1,000-1,500 feet. During the second generation two pontoon systems became 

standard. Notable designs include the Aker H-3.0, SEDCO 700 and the Friede and Goldman 

Pacesetter class (Figure A.19). Most of the first and second generation semis have now been 

retired, upgraded or converted to other uses such as floating production systems and 

accommodation vessels. 
11

Third Generation 

Third generation rigs were built from 1982 to 1986 and increased the size, payload and 

standards of redundancy in earlier designs (Halkyard, 2005). Third generation rigs were designed 

to operate in water depths up to 2,500 ft. In total, 44 third generation rigs were built, and many 

were upgraded in the late 1990’s and early 2000’s to increase their water depth capability and are 

still in service (Gavankar and Rammohan, 1998). These vessels make up the majority of the 

existing midwater fleet (Figure A.20). 

Fourth Generation 

Fourth generation rigs are large units (30,000-53,000 ton displacement) capable of handling 

high variable deck loads (4,000-6,200 ton) and mud volumes (3 x 1,600 hp). Pipe handling on 

fourth generation semis is automated and enhanced blow out preventer (BOP) controls are 

standard. Dynamic positioning was incorporated in some second generation rigs, but become 

more common in fourth generation units. Due to the low oil prices and reduced demand for 

drilling in the late 1980’s and 1990’s, only 13 fourth generation units were built (Keener et al., 

2003). The GVA 4500 is a typical design. 

Fifth Generation 

The fifth generation of semisubmersible construction occurred in the late 1990’s and early 

2000’s. During this period, oil prices were still low, but technology had matured so that 

deepwater and ultradeepwater drilling was possible and fifth generation rigs began to explore 

these regions. In fifth generation rigs, drill floor systems, power management, vessel 

management, dynamic positioning, and BOP controls are integrated and computer controlled. 

Most fifth generation rigs are approximately the same displacement as fourth generation rigs, but 

have improvements in water and drilling depth capability, due in part to dynamic positioning. 

Fifth generation units often have triply redundant dynamic positioning, powerful mud systems, 

and automated pipe handling. Most have a dual activity derrick or significant off-line activity 

and can operate in 7,500 to 10,000 ft water depths. 

Sixth Generation 

Rigs built after 2005 are considered sixth generation units (Figure A.21). Sixth generation 

units were typically ordered in response to the increasing oil prices and dayrates in the late 

2000’s and the requirements to drill deeper more complex wells. Sixth generation rigs have 

water depth capability of 10,000 ft and use a modular top drive system. All sixth generation 

semis are dynamically positioned and are more mobile than their predecessors and capable of 

self-propelled speeds up to 8 knots. New designs frequently have two fully functional derricks 

and may incorporate a multi-purpose drilling tower instead of a conventional derrick. 
12

1.4.5. Upgrading 

A semisubmersible that is upgraded to drill in deeper water would be classified either as an 

upgraded or as an “equivalent” higher generation unit. For example, if a second generation rig 

was upgraded to drill in 3,500 ft water depth, with mud pump capacity 3 x 1,600 hp, variable 

displacement load of 4,300 tons, top drive and automatic pipe handling, the rig would be 

classified as a fourth generation unit. 

1.5. DRILLSHIPS

1.5.1. Early Drillships 

The first drillships were built in the late 1950’s and 1960’s and were structurally and 

functionally diverse (Figure A.22). Some first generation vessels used early dynamic positioning 

systems, but most were moored. By the late 1960’s the basic layout of drillships was 

standardized. A typical design from this period is the Glomar III class (Figure A.23). 

In the early 1970’s, the first modern dynamically positioned drillships were built. These 

included the Gusto Pelican Class and SEDCO 445 class. These vessels were generally capable of 

operating in 2,000 to 3,500 ft water depths, approximately twice the depth of contemporary 

semisubmersibles. These vessels generally had 15,000 ton displacements and were capable of 

drilling 20,000 ft wells. Moored drillships continued to be built and some moored vessels had 

capabilities that matched or exceeded dynamically positioned drillships. By the late 1970’s the 

capabilities and size of drillships had increased. For example, Discoverer Seven Seas delivered in 

1976 was capable of drilling in 7,000 ft water depths and displaced 22,000 tons. Discoverer 

Seven Seas and several other drillships from this period are still active. 

1.5.2. Modern Drillships 

Between the mid 1980’s and late 1990’s, no new drillships were ordered. Before the late 

1990’s, generations were not used to describe drillship construction, and the first four 

generations of drillships are not well defined in the literature. When the Discoverer Enterprise

was delivered in 1999 it was described as a fifth generation vessel, analogous to the fifth 

generation semis that were being built at the time (Figure A.24). Fifth generation drillships were 

significantly larger than previous designs (45,000 to 100,000 ton displacements) and capable of 

drilling in 7,500 to 10,000 ft water depths; nearly all are dynamically positioned. 

In the mid 2000’s contractors began to refer to newbuilds as sixth generation vessels (Table 

A.7). Sixth generation designs increased the maximum water depth to 12,000 ft and dual activity 

derricks became standard (Figure A.25). In some cases, surface BOP capabilities were included 

in addition to the standard subsurface BOP. In 2011, contractors reported ordering seventh 

generation units, but the improved capabilities of these units are not yet clear. 
13

1.5.3. Displacement 

Table A.7 describes the displacement of common sixth generation rigs. There is wide 

variation in drillship size with displacements ranging between 50,000 and 100,000 tons.3 Smaller 

drillships (e.g. the Gusto PRD 10,000) sacrificed functionality to reduce costs, but large designs 

such as the Samsung 12,000 are the most popular. In Figure A.26, Discoverer Enterprise, a 

100,000 ton drillship is compared to the 22,000 ton Discoverer 534 drillship built in 1975 and 

Transocean Richardson, a 4th generation semi. 

1.5.4. Competition with Semis 

Drillships and semis compete for many of the same drilling programs, and which is better for 

a specific job is usually determined by availability and technical factors. Drillships can operate 

for up to three months without resupply, which reduces the spread requirements and allows for 

efficient work in frontier regions or far from shorebases. Drillships are also able to mobilize 

more rapidly than semis, and in some cases, have more advanced drilling equipment, but the 

ship-shape layout also limits space for operations relative to the semisubmersible’s square

shaped deck. Drillships are usually valued for exploratory and appraisal drilling in deepwater 

frontier regions. However, semis have more favorable motion characteristics than drillships and 

are favored for most harsh environments and if the drilling program requires closely spaced 

wells. 

1.6. ACTIVITY STATES

Rigs transition through several distinct stages over their lifecycle (Figure A.27). 

1.6.1. Active 

Active rigs are working under contract and are the only state in which they receive income. 

Rigs receive income on a dayrates basis which is a rental charge for each day the rig is under 

contract, and includes the use of the rig and crew, but does not include most other costs 

associated with drilling the well. Dayrates vary depending on whether the rig is drilling, 

undergoing repairs, standing by, or in a mobilization/demobilization phase (Moomjian, 1999). 

Contracts may be on a term or fixed-well basis. Term contracts specify contract duration; 

fixed well contracts specify the number of wells to be drilled. Term contracts are more common 

in most regions and markets, however, fixed well contracts are more common in the GOM 

jackup market. Fixed well contracts are typically used for short-term projects while term 

contracts are used for longer projects. 

1.6.2. Ready-Stacked 

Active rigs transition to inactive status when their drilling contract (work obligation) expires. 

If a rig is to be idled for a short period of time, the rig is typically maintained in a prepared or 

“ready-stacked” state. Ready-stacked rigs are idle but available for immediate use with minor 

preparation. In a ready-stacked state, normal maintenance operations similar to those performed 

when the rig is active are continued so that the rig remains work ready. Ready-stacked rigs are 

 

3 For scale, a Nimitz class aircraft carrier is approximately 100,000 tons. 
14

actively marketed and considered part of marketable supply. A hot-stacked rig is fully staffed 

and ready for immediate work. A warm-stacked rig requires minor preparation and the rehiring 

of semi-skilled workers. 

1.6.3. Cold-Stacked 

If operators do not expect a rig to be utilized in the near term, the rig is “cold-stacked.” Coldstacked rigs are frequently inactive for a period of several months to one or more years. Coldstacked rigs are generally not considered part of the marketable supply and may not be counted 

in supply and utilization statistics. Cold-stacked units are stored in a wet dock (Figure A.28) and 

require capital and time to return to working condition. Cold-stacked rigs are maintained using 

inhibitive chemicals, and depending on the length of inactivity and value of the unit, doors may 

be welded shut and guards may be placed on duty to protect from vandalism. To bring back a 

cold-stacked rig into operational condition, a crew must be rehired and a series of inspection and 

testing procedures are required including power, load, and pressure testing; BOP certification; 

riser and tensioner inspection; and a host of other service checks (Aird, 2001).

Reactivation expenses vary widely depending on how long the rig has been out of service. 

For jackups, reactivation can range from $4 to $20 million and take up to 9 months (Rynd, 

2012). For semis, reactivation can cost up to $50 million and take 12 months. Due to these high 

costs, rigs are reactivated only after receiving a contract commitment, or if the contractor is 

confident the rig will successfully compete and win a work contract. 

1.6.4. Dead-Stacked 

A rig will transition between inactive states many times throughout its life, and as a rig ages, 

it will spend an increasing portion of its time cold-stacked. After being cold-stacked for several 

years, reactivation costs become prohibitive and a rig is labeled “dead-stacked.” Dead-stacked 

rigs are used for parts before being retired and may remain dead-stacked for many years before 

being dismantled. Figure A.29 shows the dead-stacked rig Zeus being dismantled in the Freeport 

Ship Channel in Texas. All the rig equipment has been removed and two legs are currently 

undergoing cutting and removal operations. 

1.6.5. Retired 

A rig is removed from the fleet when it is sold for scrap, lost due to a catastrophic event 

(Figure A.30), or converted to another use. Conversion to a mobile offshore production unit or an 

accommodation unit is the most common alternative use. Rigs destroyed by hurricanes are 

scrapped or may be cleaned and towed to an approved reef site. 

1.7. RIG COSTS 

Rigs and rig markets are described by newbuild and replacement costs. Newbuild costs are 

the costs charged by shipyards to build a rig. Replacement costs are an estimate of the costs to 

replace an existing rig with a new rig of like quality. 
15

1.7.1. Newbuild Costs 

Average newbuild costs by rig type are provided in Table A.8 for the 141 rigs under 

construction circa 2012. Jackups cost on the order of $200 million while semis and drillships cost 

approximately $600 million with drillships being slightly more expensive. There is wide 

variation in newbuild costs with some jackups exceeding the costs of some semis and some 

drillships costing over $1 billion. 

1.7.2. Replacement Costs 

Replacement costs are used for underwriting and financial valuation purposes to value the 

cash generating assets of drilling contractors. Replacement costs are not based on the depreciated 

newbuild costs of a rig or on second-hand market valuations, but are estimated by reference to 

the current newbuild market. Therefore, as prices in the newbuild market increase, replacement 

cost estimates respond similarly. Table A.9 shows replacement costs for selected Transocean rigs 

in early 2012. Due to robust activity in the newbuild market, replacement costs are relatively 

high, even for older units. 
17

2. THE FIVE OFFSHORE RIG MARKETS 

Contract drilling services are supplied by the newbuild and secondhand markets, are 

maintained and enhanced in the upgrade market, and complete their lifecycle in the scrap market. 

Each of the five markets engages in the trade of a unique service or good and differs with respect 

to key characteristics. The purpose of this chapter is to introduce the players, pricing, size and 

revenue of each market. 

2.1. RIG MARKETS

2.1.1. Organization 

The offshore rig industry is described by five markets: newbuild market, contract drilling 

market, upgrade market, secondhand market, and scrap market (Figure B.1). 

2.1.2. Contract Drilling Services Market 

In the contract drilling market, rigs are leased to exploration and production (E&P) firms to 

drill or service wells. E&P firms include international oil companies (IOCs), national oil 

companies (NOCs) and independents. The contract drilling market is the largest and most closely 

followed of the five markets and drives the activities of investors in the other markets. 

2.1.3. Newbuild Market 

The newbuild market is a specialized shipbuilding market in which labor and capital are used 

to convert steel and third party equipment into rigs. Drilling contractors enter into turnkey 

contracts with shipyards for the delivery of one or more rigs or yards may build on speculation. 

2.1.4. Upgrade Market 

Regular maintenance is required for safe and efficient operations and as a rig ages, its 

technology becomes obsolete and upgrades are required to sustain competitiveness and market 

value. The upgrade market is a ship repair market which both upgrades and maintains rigs for 

contractors. Shipyards in the newbuild market are often active in the upgrade market. 

2.1.5. Secondhand Market 

In the secondhand market, rigs are sold among drilling contractors and between contractors 

and other market participants. Rigs may be sold for use in the service market, may be converted 

to another use by the buyer, or sold for scrap. 

2.1.6. Scrap Market 

In the scrap market, shipbreaking firms buy rigs on the secondhand market, either directly 

from drilling contractors or from brokers. Equipment is reused where possible and the rig is 

dismantled with the steel recovered and sold for scrap to mini-steel mills. The scrap market is the 

smallest and least transparent of the five markets. 
18

2.1.7. Cash Flows 

Cash enters the contract drilling market when E&P firms purchase services from contractors. 

Drilling contractors use this cash to operate their units and acquire new rigs for their fleet and 

upgrade and maintain existing rigs. The newbuild and upgrade markets are the primary 

mechanisms by which capital expenditures leave the service market. Most transactions in the 

secondhand market occur between players in the contract drilling market. 

2.1.8. Market Size 

In 2010, the contract drilling market generated approximately $45 billion in revenue; 

approximately $18 billion flowed to the newbuild market which was associated with a peak in 

newbuild deliveries. Between $1 to $2 billion in capital expenditures was spent on rig upgrades 

and the secondhand market realized approximately $7 billion in market exchanges between 

companies. The scrap market is very small relative to the other markets and is usually valued at 

less than $50 million per year. 

2.2. CONTRACT DRILLING MARKET

2.2.1. System Measures 

The contract drilling market is described by dayrates, utilization and fleet size. Dayrate is the 

daily rental fee charged by the rig owner and includes the use of the rig and labor costs, but does 

not include most other costs associated with well construction (e.g. equipment rental, chemicals, 

casing, etc.). Dayrates behave according to demand and supply conditions and as rig demand 

exceeds supply, dayrates generally rise, and when there is too much supply, rates fall. Demand 

for contract drilling is driven by the capital spending patterns of E&P companies, which, in turn, 

is based on producer’s expectations of future oil and natural gas prices, price volatility, and the 

availability and risks associated with exploring for and developing hydrocarbon resources. 

Dayrates are an indicator of market conditions and where company revenues are heading, and 

generally speaking, the same drivers that impact dayrates tend to drive the rest of the offshore 

service and support industry, so when rig dayrates rise, so does the cost of supply boats, 

helicopters, cementing, mud, wireline logging, etc. 

Utilization is a system measure defined by the proportion of rigs working to the total fleet 

(i.e. active rigs/total fleet). Industry capacity is not a limited resource because companies can add 

rigs to respond to higher demand from producers and stack rigs when demand declines. While 

adding capacity takes years, drilling rigs have very long lives (25+ years) and when demand 

weakens, overcapacity in the market leads to prolonged declines in pricing. Utilization is a 

measure of the spare capacity in the market and can be computed at various levels of aggregation 

(i.e. firm, regional, submarket levels). High utilization rates cause dayrates to rise and provide a 

signal to operators that additional capacity can be absorbed in the market. Regionally elevated 

utilization rates lead drilling contractors to reposition fleets while globally high utilization rates 

encourage newbuilding investment. 

Fleet size describes the total number of rigs of a given water depth or class. Fleet size is 

described by firm and when reported regionally is an indicator of the total capacity in the drilling 

market. The scale and quality of a drilling contractor’s asset base is correlated with its revenue 
19

base. A large asset base implies a platform for sustainable earnings and cash flows and is related 

to a company’s market position, its ability to compete in terms of cost structure and the ability to 

obtain financing for capital projects. 

2.2.2. Players 

The major players by 2011 rig counts are shown in Table B.1. Cold-stacked rigs are included 

in the count. In 2011, the fleet included 868 rigs. Fleet sizes change over time, but the changes 

are often slow and represent a small portion of a companies’ asset base. The service market is 

dominated by a small number of publicly traded firms including Transocean, Noble Drilling, 

ENSCO, Diamond Offshore and Seadrill. In total, there are approximately 100 rig operators, but 

the top four firms – Transocean, Noble Drilling, ENSCO and Diamond Offshore – own 36% of 

the rigs and the top eight firms own over 50% of the rig fleet. There are many small players and 

the sector is highly fragmented which has led to consolidation over time. 

The need for offshore drilling has evolved over time and in 2011 the service market is 

distributed throughout the world in the GOM, Brazil, Persian Gulf, Southeast Asia, India, China, 

the North Sea, Mexico and elsewhere (Table B.2). The top eight regions contain approximately 

85% of the active fleet in 2011. Smaller markets include the Mediterranean, the Red Sea, Black 

Sea, Caspian Sea, Eastern Canada, the Caribbean and Western Australia. Frontier regions include 

the Arctic Ocean, East Africa, Ghana, and the Philippines and typically contain less than five 

rigs. 

2.2.3. Prices 

Dayrates are the primary contract specification during the bidding process and are highly 

variable over time and between regions. Dayrates are often announced by drilling contractors and 

are monitored by industry observers and assembled by commercial data providers (such as 

RigLogix, ODS-Petrodata, RigStar and RigData). Contract lengths are often less than a year in 

duration and so there is a steady stream of new contracts each month that provides a transparent 

and reliable indicator of the industry. 

In Figure B.2, the six month moving average4 of jackup and floater dayrates in selected 

regions are depicted. Prices were relatively stable from 2000 to 2005 before increasing sharply 

from 2005 to 2007 as oil prices rose; prices stabilized throughout 2007 and 2008, but following 

the 2008 recession; prices fell, especially in the more volatile jackup market. 

In the jackup market, there are significant interregional differences. In the 2009 to 2011 

period, jackup dayrates ranged from 50,000 to 100,000 $/day in the U.S. GOM compared with 

100,000 to 175,000 $/day in the North Sea. Interregional dayrate differences in the jackup 

market are due to oversupply in the U.S. GOM, the large number of low spec rigs in the Persian 

Gulf and U.S. GOM, and the high cost of harsh environment jackups in the North Sea. 

In the floater market, there is less variation between regions due to patterns of supply and 

demand, technical requirements, and the similarity of deepwater drilling rig capacity. In the 

 

4 Moving averages were computed to smooth the month-to-month variation and improve the presentation. 
20

2009-2011 period, floater dayrates generally ranged between 300,000 and 500,000 $/day with 

slightly lower dayrates in Southeast Asia than in the Atlantic basins. 

2.2.4. Market Size 

Since 1994, 2,500 to 3,700 wells have been drilled each year (Figure B.3). The number of 

deepwater (>400 m) wells has grown over the past 15 years while the number of shallow water 

(<400 m) wells has fluctuated. While many market participants are focused on the more lucrative 

deepwater segment, most drilling still occurs in shallow water. Figure B.4 shows the geographic 

distribution of offshore drilling in 2011. Asia accounted for nearly half of drilling activity while 

the Atlantic basins of North and South America, West Africa and the North Sea accounted for 

remaining activity. North America activity is dominated by drilling in the U.S. GOM, but due to 

the Macondo blowout on April 20, 2010, and subsequent drilling moratorium, activity levels are 

depressed relative to historic levels 

2.2.5. Market Value 

The market value of the offshore drilling market in 2010 is shown in Table B.3. We counted 

the number of rigs of each class active in each month and region, and multiplied by the average 

regional dayrate. We estimate that E&P firms paid approximately $43 billion to drilling 

contractors in 2010. Despite the fact that deepwater drilling makes up a relatively small 

proportion of the number of offshore wells drilled, the deepwater market accounts for 

approximately two-thirds of market revenue. Over the past decade, the contract drilling market 

has varied from $25 to $50 billion (Figure B.5) 

Market valuation is subject to uncertainty. Large markets with a high degree of involvement 

by IOCs and publicly-traded drilling contractors are transparent and may be estimated with a 

degree of confidence. However, for small markets or those dominated by NOCs and state-owned 

drilling contractors, our confidence in the estimates declines and it is particularly difficult to 

reliably estimate the size of the Chinese market due to the large number of state-owned rigs. 

Additionally, the U.S. GOM data are complicated by the Macondo blowout which reduced the 

number of rigs operating in the GOM for much of 2010. 

Table B.4 compares our estimates to those of the market intelligence firm INTSOK. Our 

results are lower than INTSOK’s across most regions and our total market value estimate is also 

lower. The difference is due to the methods of analysis and the definition of the market. We only 

estimated payments to drilling contractors for MODU services, while INTSOK’s estimates also 

include well management and platform rig costs. 
21

2.3. NEWBUILD MARKET

2.3.1. System Measures 

The newbuild market is specified by the number of deliveries and their prices. The market is 

transparent because newbuilding is a significant capital expenditure for drilling contractors and a 

significant source of revenue for rig-building shipyards. Prices are widely reported for 

investment purposes and tracked by the same firms that survey dayrates. 

Drilling contractors order rigs when the expected rate of return (or net present value) from 

operating a new rig exceeds internal investment criteria. The benefit of investment depends on 

dayrates and utilization rates over the lifetime of the rig. Since these are unknowable, 

assumptions based on current market conditions are used. As market conditions change, the 

assumptions used in financial analysis respond, and investment in newbuilding may be justified. 

Since the newbuild market depends on dayrates and utilization rates in the contract drilling 

market, the cyclical nature of the contract drilling market causes similar but delayed cycles in the 

newbuild market. 

Prices in the newbuild market are a function of demand and labor prices at shipyards, 

equipment costs and steel costs. As demand at shipyards increases, backlogs develop and 

shipyards are able to demand higher prices. In addition, demand at rig-building shipyards is 

generally associated with demand across the drilling supply chain. Therefore, demand and prices 

for drilling equipment typically increase along with demand at shipyards and this leads to further 

price increases. 

2.3.2. Players 

The largest shipyards in each segment of the market in the first quarter of 2011 are presented 

in Table B.5. The jackup market is dominated by Keppel and its subsidiaries, while the drillship 

market is dominated by Daewoo and Samsung. Keppel has shipyards located throughout the 

world, while the Daewoo and Samsung yards are located in Korea. The semi market is currently 

distributed among five Asian shipyards. Table B.6 shows the number of rigs under construction 

by nation circa 2011 and estimated capital expenditures. Measured by capital flows, the rig 

building industry in South Korea is approximately twice as large as the Singaporean industry, 

however, this is due to the current boom in drillship construction and may not continue after the 

current round of drillships are delivered. 

2.3.3. Prices 

Figure B.6 shows the average construction costs of jackups and floaters during the most 

recent newbuild cycle. The costs of jackup rigs increased from approximately $100 million for 

rigs delivered in 2004-2005 to approximately $200 million for rigs delivered in 2012-2013. The 

price difference between high-spec (>350 ft) and standard (<350 ft) jackups varied only slightly 

over most of the cycle. When price differences were significant (as in 2010-2011) it was because 

several expensive harsh environment high-spec jackups were delivered, rather than any real 

differentiation in cost. Both ends of the jackup newbuild market respond to the same market 

stimuli due to similarities in the rigs and the firms engaged in construction. 
22

Drillships are usually more expensive than semisubmersibles with premiums ranging from a 

minimum of $69 million in 2011 to $275 million in 2012. Newbuild prices for semis peaked in 

2011 while prices for drillships peaked in 2012 and average prices for 2013 deliveries are lower 

than 2012 levels for both rig classes. 

2.3.4. Market Size 

Figure B.7 illustrates the long-term history of the newbuild market. The market is cyclical 

and has exhibited several cycles over the past four decades. From the beginning of the industry 

in the U.S. in the late 1950’s through mid-1970’s the industry spread to Europe and Asia as 

activity levels increased. Before 1974, a total of 22 jackups and 18 floating units had been 

delivered. In the late 1970’s and early 1980’s, oil prices rose and the market grew rapidly, 

peaking in 1982 when 70 jackups and 11 floaters were delivered. 

Oil prices declined in the early 1980’s and demand collapsed; between 1986 and 1997, a total 

of 37 rigs were delivered. By the late 1990’s, drilling technology had advanced to allow 

exploration in ultra-deepwaters, but few rigs were capable of ultra-deepwater drilling. Drilling 

contractors responded by upgrading existing rigs and ordering a limited number of floaters, the 

first of which were delivered in 1998. Jackup orders also began in this period, due to concerns 

about the age of the fleet and interest in more challenging reservoirs. 

During the 2000 to 2005 period, approximately five jackups and five floaters were delivered 

each year. In 2005, the number of jackup orders increased dramatically followed by an increase 

in floater orders, due in large part to increasing oil and gas prices. Jackup deliveries peaked in 

2009 when 38 rigs were delivered, while floater deliveries peaked in 2011 with the delivery of 

52 rigs. In every year since 2000, high-spec jackup deliveries have outnumbered standard 

jackups and in 2011, only 3 standard jackups were delivered compared to 33 high-spec rigs. 

2.3.5. Market Value 

The value of the newbuild market is estimated5 by summing the prices of rigs delivered in a 

given year. Figure B.8 depicts the value of rig deliveries by year. The value of the newbuild 

market peaked in 2010 at approximately $18 billion. In most years, floaters have made up the 

majority of the market value while jackups make up the majority of deliveries. 2009-2011 

witnessed a peak in market revenue due to the high demand in the 2007-2009 period. Orders 

declined in 2009 and 2010 due to the recession, and as a result, market revenue in 2012 is 

expected to be low. 

 

5 The values computed underestimate the market size because cost information is not available for all rigs. Data 

for some rigs, such as those built by a state-owned shipyard for a state-owned drilling contractor, are not publicly 

released. 
23

2.4. UPGRADE MARKET

2.4.1. System Measures 

Rigs periodically undergo maintenance and upgrades, and the scale of these modifications 

can vary considerably. Periodic maintenance occurs over a three to ten year period and typically 

consists of painting, replacing corroded or worn components, upgrading living quarters, and 

changing out machinery and equipment. Maintenance is performed to repair defects, 

accommodate customer demands, or maintain the useful life and value of the rig. Maintenance 

does not increase the value of a rig and is typically billed to operating accounts and require 

between several days and several months to perform. 

In addition to periodic maintenance, rigs are generally upgraded at least once over the course 

of their lifetime to improve technology and maintain competitiveness. Rig upgrades involve 

significant capital expenditures and often involve structural changes to the rig including adding 

dynamic positioning, increasing leg length, adding cantilever capability and increasing variable 

load (Dupuis and Hancock, 2008; Snyder and Childers, 1989). Installation of new drilling 

equipment is also common. Upgrades increase the value of the rig and its replacement cost and 

are considered a capital expenditure. Upgrades require at least several months to perform. 

There are three categories of upgrade and refurbishment costs (Seeking Alpha, 2011). In 

some cases, E&P companies require modifications to a rig before commencement of a contract. 

These typically do not significantly alter rig specifications and are charged to the E&P company, 

either as a lump sum payment or amortized over the duration of the contract. Contractors spend 

money to maintain the rig in an acceptable state; these costs are considered operating 

expenditures. Finally, there are costs incurred to upgrade the specifications of the rig or extend 

its life; these costs are considered capital costs. 

2.4.2. Players 

There are minor infrastructural requirements for most maintenance activity, and in many 

cases, repairs and maintenance can be performed at local ports without shipbuilding or 

drydocking facilities (Wahlberg and Williams, 2010). More intensive upgrades are conducted at 

specialized facilities. The shipyards conducting major upgrades in 2009 and 2010 are given in 

Table B.7. Lamprell and Keppel are the dominant players and no other shipyard upgraded more 

than one rig. Other firms active in the upgrade market include Signal International in the U.S., 

Gulf Cooper in the U.S., Drydocks World in the U.A.E., Larsen and Toubro in Oman, Malaysia 

Marine and Heavy Engineering in Malaysia, Maua Shipyard in Brazil, PD&MS in the U.K., 

Rijeka Shipyard in Croatia, and Remontowa in Poland. 

2.4.3. Prices 

Tables B.8 to B.10 provide a sample of jackup, semi and drillship upgrade contracts. The 

scale of upgrades varies widely, and the scope of work allows the variation in cost to be better 

understood. 
24

In Table B.8, recent jackup upgrades have cost between $10 and $30 million. These upgrades 

may include painting, upgrades to drilling equipment, upgrades to accommodations, the 

replacement of piping or electrical systems, and inspection and repair of legs and spudcans. 

Upgrade costs can exceed $50 million but at higher prices many firms choose to newbuild rather 

than upgrade (Maksoud, 2002).

Floater upgrades vary significantly in price from $15 to $340 million (Tables B.9 and B.10). 

At the high end of this range are complete rebuilds in which the firm uses an existing hull and 

replaces nearly all other components. At the low end are modifications to a small number of 

systems or components. The $152 million upgrades of Noble’s drillships Roger Eason and Leo 

Segerius are representative. These upgrades added a new stern block including 85% of the ships’ 

marine operating systems, refurbished the derrick, replaced the top drive, replaced cranes, and 

increased the power of the dynamic positioning system. 

2.4.4. Market Size 

The number of major upgraded rigs delivered between 2000 and 2010 is shown in Table 

B.11. Major upgrades require several months and would be considered capital expenditures. On 

average, 17 jackups, and 13 floaters were upgraded each year, and there were notable peaks in 

2004 and 2007 approximately coinciding with the timing of newbuilding orders. This suggests 

that firms invest in upgrading under roughly the same conditions in which they invest in 

newbuilding. In total, 287 rigs were upgraded between 2000 and 2010, representing 

approximately half of the active fleet. 

2.4.5. Market Value 

Estimating market revenue is complicated by the range of costs associated with upgrades and 

the definition of what constitutes an upgrade. Therefore, we provide a range of market values by 

assuming a minimum and maximum expected upgrade cost per rig. We estimate that jackup 

upgrades cost at least $10 million and each floater upgrade costs at least $75 million; at a 

maximum, we estimate the upgrade costs as $25 and $250 million for jackups and floaters, 

respectively. Upgrade costs for individual rigs may fall outside of this range, but we expect the 

average cost in the 2010-2012 period to fall within these values. Given these assumptions, the 

upgrade market is estimated to have an average value of between $1 and $3.4 billion per year. 

2.5. SECONDHAND MARKET

2.5.1. System Measures 

The secondhand market includes a broad range of transactions. Rigs sold on the secondhand 

market may be old or may be newbuilds; units may be sold through mergers, liquidations, or 

private transactions; rigs may be sold with or without an existing contract backlog, and buyers 

may continue to use the vessel as a rig or may convert it to another use. 

Transactions are conducted for a wide variety of reasons, reflecting the diversity of 

transaction types. In some cases, firms sell rigs due to bankruptcy; Hercules’ purchase of 

Seahawk’s rigs and Seadrill’s purchase of PetroProd’s rig are examples. In other cases, firms sell 

rigs to eliminate non-core assets. Frequently, this involves a large drilling contractor selling older 

rigs to a low-spec specialist; for example, Diamond and Transocean have both divested older 
25

jackups in recent years. Finally, rigs may be purchased through the takeover of one firm by a 

larger firm; examples include Seadrill’s purchase of Scorpion and Transocean’s purchase of 

Aker Drilling. 

2.5.2. Players 

The number of transactions by major market players between 2005 and 2010 is shown in 

Table B.12. Hercules and Seadrill have been the biggest buyers in the secondhand market while 

Transocean has been the biggest seller. Seadrill has targeted newbuild and high-spec rigs while 

Hercules has focused on less-expensive, low spec units. Transocean has been active in divesting 

older rigs, particularly jackups. Songa has been active on both sides of the market. 

2.5.3. Prices 

Prices on the secondhand market are determined in part by the net asset value (NAV) of the 

rig. NAV is an estimate of the net revenue generation potential by a rig over its remaining life. In 

the absence of market constraints the secondhand price should approximate the NAV, however, 

imperfect information, supply-demand imbalances, and financial pressure (e.g. bankruptcy) may 

cause NAV and secondhand market prices to differ. 

Table B.13 shows the range in costs of rigs purchased on the secondhand market in 2005-

2010. The range in secondhand prices is large and this is due to the variance in rig age and 

factors related to the buyer and seller and market conditions. The minimum value of a rig on the 

secondhand market is $5 million for both jackups and floaters and this is approximately equal to 

the scrap value of a rig. Low-priced transactions are frequently associated with conversion to 

another use. 

The maximum price for a secondhand rig can, in theory, exceed the price of a newbuild rig. 

Secondhand rigs may be sold with an existing contract backlog, and this is particularly common 

when one firm buys all of the rigs from another firm; recent examples include Seadrill’s 

purchase of Scorpion, Hercules’ purchase of Seahawk Drilling, and Transocean’s purchase of 

Aker. Sale with a contract backlog will increase the NAV. Secondhand rigs may also be more 

valuable than newbuild rigs because they are available immediately while newbuild rigs may 

only be delivered after a multi-year delay. This allows secondhand rigs to begin generating 

revenue immediately, increasing NAV. In recent years, secondhand prices for recently built rigs 

have been approximately equal to the newbuild price. 

2.5.4. Market Size 

Table B.14 shows the number of rigs sold through the secondhand market from 2005 to 

2010. On average, about 20 rigs were sold each year with the majority being jackups. From 2005 

to 2010, jackups transacted the most (82), followed by semis (31) and drillships (13). 

2.5.5. Market Value 

The total annual size of the secondhand market is estimated to be on the order of $2 to $4 

billion (Table B.14). When cost data for a particular transaction were not available, the value of 

the transactions was estimated based on the age of the rig, its water depth capability, and the 

average cost of similar transactions in that year; a conservative approach was used for these 
26

estimates and as a result the values in Table B.14 are likely to underestimate the value of the 

secondhand market. High market value in 2010 was due to three transactions: the purchase of 

Skeie Drilling by Rowan, the purchase of Scorpion by Seadrill, and the purchase of Frontier by 

Noble. Each of these transactions exceeded $1 billion. 

2.6. SCRAP MARKET

2.6.1. System Measures 

In the scrap market, cold-stacked rigs are sold to specialized shipbreaking firms for 

dismantling and recycling (Kaiser, 2008). Owners place a premium on resale and reuse options 

and a low priority on scrapping because of the significant residual value in units, and as a result, 

rigs are rarely scrapped unless they have sustained damage from storms, blowouts or other 

accidents. Between 2005 and 2011, just seven rigs were sold for scrap (RigLogix, 2011). 

Rig scrapping is a small part of the larger ship breaking industry concentrated in India, 

Pakistan, China, Turkey and Bangladesh (Saraf et al., 2010). Shipbreaking that occurs in the U.S. 

is primarily driven by disposal of U.S. Navy ships and other federal vessels and very little rig 

hull deconstruction occurs domestically. Between 2005 and 2010, only one rig (the jackup Zeus) 

was dismantled in the U.S. without first receiving storm damage (Arnold and Itkin, 2008).

2.6.2. Players 

Very few drilling contractors scrap rigs. Hercules is the only major drilling contractor to sell 

a MODU to a scrapyard in the 2005 to 2011 period, and has sold six jackups and one 

submersible during this period. In addition, Seadrill sold one tender for scrap. 

Rigs are occasionally scrapped after being damaged in hurricanes if repairs are uneconomic. 

For example, Ocean Warwick was badly damaged during hurricane Katrina and drifted 60 miles 

before being grounded. The rig was sold to Nabors, repaired, and is currently operating as 

Nabors 660. When rigs are scrapped following damage, a marine salvage firm (i.e. Smit) is 

contracted to remove the rig from its offshore location, and the rig is typically transported to the 

nearest shipyard and scrapped. 

2.6.3. Prices 

Most of the value in an obsolete rig lies in the drilling equipment which is removed and sold 

before the rig is scrapped. Vessels are sold to ship breaking firms directly or via brokers on a per 

ton basis and the value of a vessel will principally depend on its weight and the labor required to 

dismantle the unit. The scrap metal price at the time of the sale is a principal factor in the value. 

In 2010 and 2011, Hercules sold five jackups for scrap ranging between $1 and $5 million and 

with an average price of $2.5 million. This is consistent with prices in the range of $300 to $550 

per ton, and is similar to scrap prices for other vessel classes. 

2.6.4. Market Value 

Given the small number of rigs scrapped per year and the low value of scrapped rigs, the size 

of the scrap market is negligible relative to the other rig markets. In many years, no rigs are 

scrapped, and when rigs are scraped the value of individual transactions are based on the rig 
27

weight and scrap metal price at the time of sale, rarely exceeding $5 million per unit. We 

estimate the average size of the market to be less than $50 million annually. As the legacy fleet 

continues to age, scrapping activity could increase and the market may grow; since many aging 

rigs are in the GOM, some of these rigs are likely to be processed by U.S. ship recyclers. The 

firms most likely to process scrapped rigs in the U.S. are ESCO Marine, International 

Shipbreaking, Marine Metals and All-Star Metals, all of which are located along the 

Brownsville, Texas ship channel. 
29

3. THE OFFSHORE CONTRACT DRILLING MARKET-SUPPLY, 

UTILIZATION, AND DAYRATES 

In the contract drilling market, E&P firms lease rigs from drilling contractors to drill wells. 

Approximately 120,000 wells have been drilled offshore since 1955, and about half of these are 

in the U.S. GOM (ExxonMobil, 1995). From 2000 to 2010, approximately 3,500 offshore wells 

were drilled each year with a growing percentage in deepwater (Douglas-Westwood, 2009). The 

purpose of the next two chapters is to characterize the offshore contract drilling market statistics 

and regional trends, contractors, business strategies, and market structure. In this chapter, we 

begin with a description of the global supply of rigs and their geographic distribution over the 

past decade. We characterize regional dayrates and utilization and the contracts that are used in 

the industry. Summary conclusions end the chapter. 

3.1. DATA SOURCES

3.1.1. Utilization and Supply 

Regional utilization rates and fleet sizes were obtained from the commercial service provider 

RigLogix and supplemented with data from Baker Hughes. RigLogix provided data on the 

number of contracted rigs and utilization rates from 1999-2011, while Baker Hughes provided 

information on the number of active rigs from 1987-2011. Contracted rigs may be drilling, 

performing a workover, waiting on location, mobilizing or under modification. Active rigs are 

defined by Baker Hughes more narrowly as rigs that are engaged in drilling and are therefore a 

subset of contracted rigs. Rigs engaged in workovers, production testing, or drilling for less than 

15 days in a month are not considered active. In the international data, a rig must be drilling 15 

days a month to be counted as active; in North America, a rig is active from the time a well is 

spudded until it reaches its target depth. Baker Hughes data does not differentiate between 

floaters and jackups. 

3.1.2. Dayrates 

Dayrate data were obtained from RigLogix. The dataset included information on 7,123 

individual contract records for jackups, drillships and semisubmersibles between January 1, 2000 

and January 1, 2011. Each contract data point included information on contract duration, 

location, water depth, and contract type. Contracts in the Persian Gulf, U.S. GOM, North Sea, 

Southeast Asia and West Africa were considered. Monthly average dayrates were computed as 

the average of the dayrates of all contracts for which drilling began in that month (Figure C.1). 

Dayrates were inflation adjusted using the U.S. BLS annual producer price index for all finished 

goods and the start year of the contract. 

3.2. SUPPLY

The world fleet of offshore drilling rigs in January 2012 is categorized by type in Figure C.2. 

Of the 868 existing rigs, 539 are jackups and 329 are floaters; 644 (87%) of the total inventory 

were active in January 2012, and of these working rigs, 404 are jackups (83% utilization) and 

259 are floaters (93% utilization). 
30

The jackup inventory is composed of 201 low spec (<300 ft, non-harsh environment) units 

and 336 high spec units (>300 ft or harsh environment); 45 of the high spec units are capable of 

drilling in harsh environments, such as the North Sea, Eastern Canada, and the Arctic. The 

floater fleet is dominated by semis (223 semis versus 106 drillships). 

Figure C.3 shows the distribution of high and low specification rigs according to contracted, 

ordered and stacked status in January 2012. The jackup and drillship fleets are dominated by 

high-specification, deepwater newbuilds (> 300 ft for jackups; > 7,500 ft for drillships) while the 

semi fleet is dominated by mid-water (< 7,500 ft) units. Semis comprise the majority of the 

floater fleet, but after the delivery of drillships under construction, drillships will comprise the 

majority of the high spec floater fleet. Most supply addition is occurring in the drillship and 

jackup markets and relatively few semis are under construction. 

3.3. GEOGRAPHIC DISTRIBUTION

Wells are drilled wherever hydrocarbon potential exists and mineral rights (concessions) are 

granted, but for geologic, economic, technological, political and historical reasons, offshore 

drilling remains concentrated in a relatively small part of the world’s oceans. 

3.3.1. Regional Characteristics 

The Persian Gulf, U.S. Gulf of Mexico (GOM), Brazil, North Sea, Southeast Asia, India and 

China are the largest markets and account for approximately 80% of the 2011 rig market (Table 

C.1 and Figure C.4). Smaller markets with less than 25 active rigs in 2011 include the 

Mediterranean Sea, Black Sea, Caspian Sea, Eastern Canada, the Caribbean and Western 

Australia. Frontier regions include the Arctic Ocean and East Africa, as well as previously 

unexplored countries in developed regions such as Ghana in West Africa and the Philippines in 

Southeast Asia (Ball, 2010). Frontier regions are defined as having less than 5 active rigs. 

Table C.2 summarizes characteristics of the major markets and Table C.3 describes the 

average water depth of jackup and floater contracts by region from 2000-2010. The average 

working water depth is a general indicator of the specification level of the rigs required in the 

region, and the standard deviation and range describe the extent of the variation required in 

drilling units. China, the U.S. GOM and Persian Gulf are the shallowest jackup markets and the 

maximum water depths in the Persian Gulf and China are approximately 300 ft. India, Southeast 

Asia and the North Sea are the deepest jackup markets and are the most likely to require high 

spec jackups. In some cases, floaters are used for shallow water drilling and this decreases the 

average water depth of floater contracts; in general, floaters used for shallow water drilling are 

older semis. The North Sea is a particularly shallow floater market because of the harsh 

environmental conditions while the U.S. GOM, Brazil and West Africa are the deepest markets. 

Table C.4 provides a snapshot of the number of contracted and ready-stacked rigs by region, 

water depth and environmental operating conditions in 2011. A number of regions have some 

harsh environment units, but the North Sea is the only region in which harsh environment units 

make up the majority of the fleet. In all other major regions, harsh environment rigs are not 

required. Table C.4 also illustrates the distribution of the fleet by water depth. The Persian Gulf, 

China and U.S. GOM have a large number of <300 ft jackups, while Southeast Asia and India 
31

are dominated by >300 ft water depth units. In the floater market, the North Sea has a large 

number of <7,500 ft units, consistent with the average water depth of wells in the region. 

3.3.2. Active Rigs 

The geographic distribution of rigs follows the capital budget allocations of firms, 

hydrocarbon prospectivity, economic and political conditions, and other factors. Figure C.5 

shows the six month moving average of the number of active offshore rigs globally and by 

region between 1987 and 2012. Active rigs include both floaters and jackups. 

The number of active rigs in the North Sea and U.S. GOM has declined over the past decade. 

In the U.S. GOM, the number of active rigs peaked at approximately 160 in the early 2000’s 

while in the North Sea, approximately 70 to 80 rigs were active throughout much of the mid to 

late 1980’s; as of 2012, only 30-40 rigs are active in each region. After the Macondo oil spill in 

the U.S. GOM in 2010, a moratorium on deepwater drilling was enacted, but with the expiration 

of the moratorium, activity has rebounded. Both Southeast Asia and Persian Gulf markets have 

seen a doubling in rig count over the past 25 years from approximately 20 in the late 1980s to 

approximately 40 in the 2007-2012 period. West Africa peaked in the late 1990’s with 35 rigs 

and declined to about half that level in the mid 2000’s before returning to the 1990’s levels in 

2012.

The distribution of rigs by country within selected regions is shown in Figure C.6. In the 

North Sea, rig activity has declined due to a decline in the U.K. sector which has been partially 

offset by growth in Norway. In the Persian Gulf, growth has been uneven over the past two 

decades and the UAE, Qatar and Saudi Arabia have all been the dominant player at different 

times. Since 2005, most growth has occurred in Saudi Arabia which has been offset by a 

reduction in Iranian offshore activity. Nigeria has been the dominant player in the West African 

market since the early 1990’s, but since 2009 there has been significant growth in Congo, Gabon, 

Ghana, Liberia, Sierra Leone and Cameroon, in part due to the end of several civil wars in the 

region. In Southeast Asia, activity levels in Indonesia and Malaysia have been relatively stable 

over the past two decades with significant growth in other nations including Vietnam and 

Thailand. 

3.3.3. Contracted Rigs 

The number of contracted jackups is closely correlated with the number of active rigs in the 

U.S. GOM (Figure C.7), but elsewhere, correlations are not as strong due in part to rigs that are 

under contract but not actively drilling (Table C.5) reflecting the way Baker Hughes counts 

active rigs in the U.S. GOM and internationally. 

The number of contracted and active rigs follows broadly similar patterns over the 1999-

2012 period (Figures C.8 and C.9). In the jackup market, the Southeast Asian and Persian Gulf 

markets have experienced consistent growth, while the North Sea market has remained relatively 

stable. West Africa has varied between 10 and 25 contracted jackups between 1999 and 2012 and 

experienced a dramatic decline following the 2008 recession. The U.S. GOM jackup market 

experienced declines in 2001 and 2009 associated with economic recessions in the U.S. and has 

seen a general decline in contracted jackups due to the maturity of the GOM shelf. 
32

In the floater market, West Africa realized consistent growth between 1999 and 2012. 

Southeast Asia has had a relatively stable number of contracted floaters over the period, with a 

slight increase between 2008 and 2012. The GOM and North Sea had a peak in activity in mid to 

late 2001, followed by a sharp decline. Since 2002, both markets have had a relatively constant 

activity level. 

3.4. UTILIZATION 

Utilization is defined as the ratio of the number of working rigs to the number of rigs 

available to work at a specific point in time. The number of available rigs can include coldstacked rigs or these units can be excluded. If cold-stacked rigs are included in the count (as is 

most often the case), then dead-stacked rigs that are counted as cold-stacked will bias the 

utilization measure downward, and regions with large numbers of dead-stacked rigs will have 

lower utilization rates. If cold-stacked rigs are not included, utilization rates would appear 

inflated and may not accurately reflect the number of rigs available to bid on a given contract. 

We report utilization rates including cold-stacked rigs. 

3.4.1. World Trends 

Worldwide rig utilization from 2000 through 2011 is shown in Figure C.10. A six-month 

moving average was applied to reduce short-term variation. At the beginning of the decade, 

jackup utilization rates exceeded floater rates, but since 2006 floaters have been more heavily 

utilized. In the jackup market, utilization declined throughout 2009 due to the economic 

recession and low oil prices; in the floater market, utilization rates declined only modestly 

between 2009 and 2011. Jackup and floater market utilization respond to different market stimuli 

and reflect differences in technology development and regional prospectivity, the timing of 

newbuilding orders and deliveries, and the impact of oil prices. There is no significant 

correlation between global jackup and floater utilization rates suggesting that regional markets 

are required to differentiate the trends. 

3.4.2. Regional Trends 

Figures C.11 and C.12 show utilization rates of jackups and floaters in selected regions. In 

the jackup market, utilization trends in Southeast Asia, the North Sea and the Persian Gulf have 

tracked each other closely over the past decade, exhibiting similar market dynamics and high 

utilization levels, while the U.S. Gulf of Mexico and West Africa have exhibited more variable 

trends over the period. In recent years, the U.S. GOM has had consistently lower utilization rates 

than other regions due to the decline in the shallow water market (Table C.6). 

In the floater market, Southeast Asia historically had lower utilization rates than other 

regional markets, except for a brief interval in 2002-2003. Brazil has especially high utilization 

rates with sustained periods of 100% utilization due to Petrobras’ role as the E&P monopolist 

which allows drilling contractors to better match demand and supply from a central decision 

making firm. In the U.S. GOM, the post-2009 decline in utilization rates has been negatively 

impacted by the Macondo oil spill. 
33

3.4.3. Interregional Correlations 

To the extent that global factors impact supply and demand conditions, utilization rates are 

expected to be correlated across regions. Conversely, if regional factors predominate, increases 

in utilization in one region may not be associated with increased utilization in another region and 

interregional correlations are expected to be poor. Oil prices, for example, form in the world 

market and provide similar signals to E&P firms worldwide, and if oil prices are a major driver 

of utilization rates, high correlations are expected; by contrast, if gas production and prices are a 

major driver of utilization in one or more regions, or regulatory factors dominate, low 

correlations are expected. 

In the jackup market (Table C.7), the U.S. GOM has the lowest correlation with all other 

regions indicating that region-specific factors in the U.S. GOM are impacting utilization. The 

Persian Gulf is poorly correlated with the U.S. GOM and North Sea due to the growth in the 

Persian Gulf market and the decline in the more mature U.S. GOM and North Sea markets. 

Utilization rates in most other regions are moderately correlated (R ≥ 0.7) indicating that global 

factors (e.g. oil prices) affect the regions similarly. 

In the floater market (Table C.8), Southeast Asia is poorly correlated with all other regions, 

suggesting that regional factors dominate the market dynamics. The small negative correlations 

between Southeast Asia and other regions indicate no relationship, rather than a meaningful 

negative relationship. In general, correlations are slightly lower than in the jackup market, and 

the U.S. GOM and North Sea, and North Sea and Brazil, are the only regions in which the 

correlation coefficient exceeded 0.7. The lower correlations among the floater fleet are believed 

to be partially due to the high utilization rates for floaters; variation in utilization in one region 

may be unable to resolve small changes in variation in another region. 

3.4.4. Market Conditions May Act to Reduce High Utilization 

When a regional fleet is highly utilized, drilling contractors respond by marketing inactive 

rigs from other regions or newbuild in the high utilization market. As these rigs win contracts, 

they are moved into the high utilization region, increasing regional fleet size and capturing 

market share; over time, if the market cannot sustain the larger fleet size, utilization rates will 

decline. Drillers with deepwater fleets often use their backlogs to maintain earnings while 

stacking surplus mid-water and shallow water rigs to support prices in the markets. 

Figure C.13 illustrates the concept of market capacity increasing in response to high 

utilization rates while Figure C.14 depicts specific examples in the Persian Gulf and Southeast 

Asian jackup markets. In both markets, utilization rates were high for a period of several years, 

and during this time contractors responded by newbuilding and moving rigs into the region 

doubling (Persian Gulf) and tripling (Southeast Asia) capacity. Eventually utilization rates 

declined. Similar patterns may not exist elsewhere or at different times. For example, in the 

North Sea jackup market utilization rates were high for an extended period without an increase in 

rig count (Figure C.15) likely reflecting the low number of harsh environment jackups capable of 

moving into the region. 
34

3.5. DAYRATES

Dayrates are the primary contract specification during the bidding process and a primary 

descriptor of the industry. Dayrates are determined by the supply and demand balance of rigs 

proxied by the utilization rate. For a given supply of rigs available to work in a given region, as 

utilization rates in the region increase, the number of rigs capable of bidding on a given contract 

declines and pricing power shifts to the drilling contractor, leading to higher dayrates. High 

dayrates provide signals to the market that the region is capable of absorbing additional rigs, and 

contractors either move units into the region or begin newbuilding. As dayrates decline and 

competition increases for contracts, drilling companies stack units or move rigs out of the market 

which acts to support prices. 

3.5.1. Trends 

In Figure C.16, the six month moving average of jackup and floater dayrates in major 

markets are depicted. From 2000 to 2005 stable dayrates generally prevailed followed by a sharp 

increase from 2005 to 2007, price stabilization in 2007 to 2009, and a decline in 2009 and 2010. 

Table C.9 reports mean dayrates by region in the 2000-2006 and 2006-2010 periods. In the 

jackup market, Southeast Asia and West Africa have very similar average dayrates, while the 

Persian Gulf and U.S. GOM are significantly lower and the North Sea is significantly higher, 

reflecting the regional supply and demand conditions and different environmental characteristics. 

The Persian Gulf and U.S. GOM are relatively benign operating environments while the North 

Sea is a harsh environment region. In the floater market, the differences in dayrates between the 

two periods are more uniform reflecting the homogenous nature of the floater fleet and capacity 

to drill wells. 

3.5.2. Interregional Correlations 

Regions differ in their geologic prospectivity, fiscal regimes, development costs, political 

risk, and strategic value (Stroebel and Van Benthem, 2010). If regions are market oriented they 

will generally respond to the same market stimuli; if regions are dominated by one or more 

NOCs, market stimuli are expected to play a less significant role in determining dayrates. As oil 

prices rise, E&P firms demand drilling leading to increases in utilization and dayrates. The rate 

of increase in each metric is not constant across regions, but the direction of the relationship is 

consistent and this creates interregional correlations. 

In Table C.10, the correlation of average monthly jackup dayrates between regions is 

depicted. For most regions, there is a modest correspondence between regions with correlation 

coefficients ranging between 0.49 and 0.90. While all correlations are statistically significant, 

dayrates in one region usually explain 25 to 60% of the variation in another region, and while 

regional dayrates do move together, significant interregional variation remains. The moderate 

correlation between regions supports the regional categorization of the market. If correlations 

between markets were close to one, it would be more reasonable to consider the regional markets 

a single global market rather than a set of interacting regional markets. 
35

The U.S. GOM jackup market is the least correlated with other regional markets which 

suggests that regional supply and demand conditions, a large number of players, onshore gas 

production, and other regional factors play a significant role in the pricing environment. West 

Africa and Southeast Asia are highly correlated suggesting similar market dynamics between 

regions. Both West Africa and Southeast Asia are relatively mature moderate water locations 

with similar environmental characteristics. This is in contrast to the North Sea, a harsh weather 

region, the U.S. GOM, which has experienced a sustained decline in rig count with shelf 

maturity, and the Persian Gulf, which has experienced a sustained increase over the time period 

assessed. 

Table C.11 shows the regional floater dayrate correlation matrix over the past decade. The 

regional correlations are higher in the floater market than in the jackup market, and this is at least 

partially due to the more global nature of the floater market. Correlations between the three 

Atlantic basin regions are higher than the correlations between any of these regions and the 

Southeast Asian market, suggesting that these three markets interact with each other more than 

they do with Southeast Asia because of their geographic proximity. 

3.5.3. Dayrate Volatility 

Volatility is a measure of the magnitude of dayrate changes over time and is calculated 

analogous to volatility metrics used in financial markets (Besley and Bringham, 2009). Volatility 

was calculated as the standard deviation of the percentage change in dayrates between quarters. 

A quarterly basis was used to reflect the minimum time to drill a well (three months) and to 

increase the sample size in each period. 

In small regions with a small number of contracts negotiated in a given quarter, the effect of 

outliers will be magnified and high volatility is expected because of the sample size. Regions that 

have a large variation in the specifications of rigs required (for example, harsh and non-harsh 

environments or broad variation in water depths) may also experience higher volatility. Figure 

C.17 illustrates the quarterly change in dayrates for the highest and lowest volatility regions in 

the jackup and floater markets. Table C.12 describes the volatility by region. The Southeast 

Asian floater market is particularly volatile, likely due to the smaller size of the market. The 

Persian Gulf jackup market is the most volatile shallow water market. Floater markets are more 

volatile than jackup markets reflecting the smaller number of contracts in the floater dataset. 

3.6. CONTRACTS

3.6.1. Dayrate vs. Turnkey 

Drilling contracts may be on either a “dayrate” or “turnkey” basis. Under dayrate contracts, 

the contractor receives a fixed amount per day for drilling the well with higher rates while the 

unit is operating and lower rates or a lump sum payment for periods of mobilization or when 

operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or 

other factors (Osmundsen et al., 2006; Moomjian, 1999; Moomjian, 1992). The E&P company 

bears all of the ancillary costs of constructing the well and supporting drilling operations and 

carries the risk for the overall success of the operation. 
36

In a turnkey drilled well, the E&P company defines the well specifications (e.g., total depth 

and target, minimum hole size at total depth, formation evaluation requirements) and retains a 

turnkey company to plan and supervise the well on a lump-sum basis (Jablonowski and Kleit, 

2006). The turnkey company subsequently retains a contractor under a dayrate contract. The 

turnkey company, not the drilling contractor, holds all of the risk of cost overruns. Turnkey 

contracts are relatively rare and are used primarily for exploration drilling by jackups when the 

E&P company is a small firm with limited financial and technical expertise (Moomjian, 1999; 

Corts, 2008). The U.S. GOM is the largest turnkey market in the world, but less than 5% of all 

contracts are estimated to be turnkey. 

3.6.2. Term vs. Well 

Contracts for drilling services may be on either a term or fixed well basis. Term contracts 

specify contract duration; fixed well contracts specify the number of wells to be drilled. Term 

contracts are more common in most regions and markets (Table C.13), except in the U.S. GOM 

jackup market and Southeast Asia floater market. Fixed well contracts are typically used for 

short-term projects while term contracts are used for longer projects; worldwide, the average 

duration of fixed well contracts for all regions over the period 2000-2010 was 106 days, while 

the average for term contracts was 456 days. 

In the shallow water U.S. GOM, jackups frequently work on a one-well basis and contractors 

have to find a new job at the completion of every well they drill. In most other markets, longterm contracts are prevalent. Table C.14 shows the average contract duration by region for 

contracts between 2000 and 2010. The average duration of jackup contracts in the U.S. GOM is 

significantly shorter than in other regions, but elsewhere deepwater and shallow water rigs 

operate under similar contracts. 

Markets that are dominated by short-term or fixed contracts may exhibit more volatility in 

dayrates than term dominated regions since negotiations occur at a higher frequency more 

closely reflecting market conditions. This would imply that the U.S. GOM jackup market would 

be more volatile than jackup markets in other regions; however, this is not the case. Instead, the 

Persian Gulf jackup market which is dominated by long-term contracts is the most volatile 

shallow water region. 

3.7. CUSTOMERS

The customers of drilling contractors vary over time by region and rig class. Table C.15 

shows the market share by E&P customers over the 2000-2010 period. Each contracted day is 

counted as one unit of market share. In general, the largest E&P customers are IOCs, but NOCs 

are the largest customers in the Southeast Asian and Persian Gulf jackup markets, and North Sea 

floater market. 
37

The U.S. GOM jackup market is relatively unconcentrated and the top four firms only control 

21% of the market. In every other market, the top four firms control at least 37% of the 

contracted days. The West African jackup market is the most concentrated; Chevron utilized 

29% of the contracted days between 2000 and 2010 and the top four firms controlled 65% of the 

market. Generally speaking, markets with low levels of concentration represent more 

competitive markets and would normally be associated with lower dayrates for all other things 

equal, and similarly, markets with a low level of customer diversity would contribute to higher 

dayrates. 

3.8. CONCLUSIONS

Over the past decade, the shallow water market has witnessed a geographic shift from the 

U.S. GOM to the Persian Gulf and Southeast Asia due to regional prospectivity and higher 

dayrates. In contrast, the major floater markets have been more stable. 

Jackup utilization rates are moderately correlated between regions except in the U.S. GOM 

because of regional factors and declining productivity. Inter-regional utilization correlations are 

higher in the jackup than floater markets, due in part to the lower variance in utilization rates in 

the floater markets. Dayrates are moderately correlated between regions. Correlations are higher 

in the floater market than the jackup market because of the regional nature of the shallow water 

market. 

There is significant volatility in dayrates and volatility is higher in the floater markets, due in 

part to the smaller number of contracts in the floater market and the larger influence of individual 

rig specifications on dayrates. The Persian Gulf jackup market and Southeast Asian floater 

markets have been the most volatile markets over the past decade. 

Markets have generally similar contract structures with most regions maintaining a mix of 

term and fixed well contracts. Most regions have roughly similar average contract durations 

between 200 to 300 days for jackups and floaters. The Persian Gulf and U.S. GOM are 

significant outliers with particularly long and short contract durations, respectively. 
39

4. THE OFFSHORE CONTRACT DRILLING MARKET–OWNERSHIP, 

VALUATION, AND MARKET STRUCTURE 

Drilling contractors hold a portfolio of rigs of different classes, qualities and specifications 

that compete in regional markets to drill wells for E&P firms. Fleet value is the sum of each rig’s 

net earnings potential over its estimated remaining lifetime based on assumed future utilization 

and dayrates. The purpose of this chapter is to describe the drilling contractors, strategies, and 

structure of the drilling market. We begin with company ownership and describe how publicly 

owned firms are valued by the market. The primary factors that impact valuation are debt and 

cash, fleet values, current and projected revenues, and net earnings. We describe how drilling 

contractors specialize and the newbuild strategies utilized by contractors. Market competition is 

characterized with an emphasis on market concentration. Summary conclusions end the chapter. 

4.1. DATA SOURCES 

Three sources of data are used in this analysis. RigLogix (2011) is an industry intelligence 

service and was used for fleet sizes, rig specifications and contract data. Jefferies (Jefferies and 

Company, Inc., 2012) is an investment analysis service and provided information on fleet 

valuation, enterprise value, revenues and capital expenditures for publicly traded firms. Annual 

reports were used to supplement and check commercial data. All financial data are as of Dec 31, 

2011. 

4.2. OWNERSHIP 

Drilling contractors are corporate entities that may be owned by investors or a government. 

Investor-owned drilling contractors may be publicly traded or privately held. Publicly traded 

corporations have a large number of shareholders whereas private firms are owned by a small 

number of shareholders. State-owned drilling contractors may be entirely owned by a state, or a 

fraction of the shares may be traded on a financial exchange. The ownership structure of the firm 

impacts business strategies, governance, access to debt and transparency. 

4.2.1. Public Firms 

Table D.1 shows the fleet size and value, revenues, and enterprise values of the largest 

publicly traded drilling contractors in the world in 2011. Enterprise value is a firm’s market 

capitalization plus its debt, minority interest and preferred equity, minus cash. Market 

capitalization is the total value of tradable shares of a company at a given point in time, 

determined by the product of stock price and the number of outstanding shares. 

The 14 firms depicted realized $26.4 billion in revenues in 2011 from 501 drilling rigs (289 

jackups, 148 semis, and 64 drillships) which we estimate is 50 to 60% of the total revenue 

generated by the industry worldwide. The fleet value is estimated at $98 billion, and collectively, 

the companies had an enterprise value of $137 billion. 

Transocean was the largest contractor in terms of fleet size and revenue, but after the 2010 

Macondo oil spill, Transocean’s share price declined because of uncertainty associated with its 

future liability (Anderson et al., 2011). As a result, Seadrill was the largest firm by enterprise 
40

value with only half the revenue and one-third the fleet size. Transocean own 141 rigs, or 16% of 

the total fleet, including 22% of the total floater fleet. Seadrill, Diamond, ENSCO and Noble 

together own 209 rigs, including 88 floaters, and account for 24% of the total fleet and 27% of 

the floater fleet. 

Transocean, Seadrill, Diamond, ENSCO and Noble are significantly larger than their nearest 

competitors and each had revenues of over $2 billion in 2011 with enterprise values of 

approximately $10 billion or more. We classify these five firms as “large-cap” and the nine 

smaller firms as “mid-market”. Large-cap firms operate large diverse fleets in a number of 

geographic regions, while mid-market firms operate smaller fleets and are more likely to 

specialize in a rig class and geographic region. 

With the exception of Seadrill, all large-cap firms are headquartered in the U.S., as are midmarket firms Hercules, Rowan, Atwood and Vantage. Seadrill and several mid-market firms are 

headquartered in Norway. Most firms are incorporated in offshore financial centers for tax 

purposes; common centers of incorporation include Switzerland, Cypress, and the Cayman 

Islands. 

4.2.2. State-Owned Firms 

State-owned drilling contractors and their 2011 fleet sizes and primary markets are 

summarized in Table D.2. State-owned drilling contractors work almost exclusively in their 

home countries and may be a subsidiary of a National Oil Company (e.g. COSL is owned by 

CNOOC) or the NOC may directly own and operate the drilling fleet. The largest state-owned 

drilling contractors are publicly traded firms in which the government is the majority shareholder 

(Petrobras, CNOOC, ONGC); most other state-owned contractors are not publicly traded. 

COSL (China) is the largest state-owned drilling contractor and owns as many rigs as 

National Drilling (UAE), ONGC (India) and Petrobras (Brazil). State-owned drilling contractors 

are smaller than public firms and the largest state-owned firms have fleet sizes approximately 

similar to mid-market public firms. In total, state-owned firms own 127 drilling rigs, or about 

15% of the world market. Most state-owned firms are jackup oriented, but COSL, Petrobras and 

Socar own semisubmersibles and ONGC owns two drillships. The top four state-owned drilling 

contractors are important players in their home markets. 

4.2.3. Private Firms 

Table D.3 summarizes the largest privately owned firms and firms that are subsidiaries of 

larger companies. Maersk Drilling is a subsidiary of A.P Moller-Maersk and Dolphin is a 

subsidiary of Fred Olsen Energy. Both companies are not traded as separate stock, and their 

activities are not as transparent or widely tracked by market intelligence firms. Most of the firms 

in Table D.3 are regional specialists with Brazil and the North Sea being the most common 

regions. 

In total, private firms own about a third of the world’s fleet and deepwater rigs. Private firms 

including Stena, Dolphin, Schahin, Odfjeld, Queiroz Galvao, and Odebrecht are important 

players in the Brazilian and North Sea floater markets and these six firms own nearly half of the 

privately-held deepwater fleet. Outside of the North Sea and Brazil, private firms are less likely 
41

to be major players. The only privately held firm frequently operating in the U.S. GOM is 

Spartan Offshore. Spartan is owned by a private equity firm and operates four low-spec jackups 

in the GOM. Approximately 50 other firms that own rigs are not shown in the table. In general, 

these firms are small, own less than three rigs and are either privately held or traded on the over 

the counter market. 

4.2.4. Market Share 

The number of days spent drilling is a measure of market share, and in Figure D.1, the total 

contracted days across all regional markets is depicted. Publicly traded firms dominate the 

market because of their larger fleet sizes, however, since 2000, state-owned drilling contractors 

have received an increasing share of the jackup market and now constitute approximately 25% of 

days on contract. In the floater market, state-owned firms account for a negligible portion of the 

deepwater fleet but private firms have increased their share over the decade and account for 

about 15% of the market in 2010. 

4.3. VALUATION

Publicly traded drilling contractors are continuously valued by the market. The primary 

factors that impact valuation are debt and cash, fleet values, current and projected revenues, and 

net earnings. Factors that are more difficult to observe and quantify that also impact market 

valuation include insurance liabilities, revenues in the distant future and customer relationships 

(Demers, 1970; Rankin, 1981; Speer et al., 2009; Slorer et al., 2011). 

4.3.1. Revenue 

Enterprise value is closely correlated with firm revenue and earnings (Figure D.2). Company 

revenue and earnings is determined by fleet composition (rig type, quality, and age) and 

geographic distribution, utilization rates, dayrates and operating cost. Firms below the regression 

lines have a lower enterprise value than would be expected based on their revenue or earnings, 

and firms above the line have a greater enterprise value than the industry average. Transocean 

and Diamond are the only two large-cap contractors that fall below the industry average. 

Transocean’s $5 billion market discount suggests its potential liabilities associated with the 

Macondo oil spill (Anderson et al., 2011). Diamond falls below the industry line due in part to its 

older fleet despite relatively strong revenues (Anderson and Hoh, 2011). Seadrill, ENSCO and 

Noble have higher enterprise values than the industry average, with the premium for Seadrill 

being particularly large due to its focus on high-specification units which have received high 

utilization and dayrates in recent years (Jefferies and Company, Inc., 2012; West et al., 2011). 

ENSCO and Noble also have higher-spec and globally diversified fleets which contributes to 

their higher valuation. 

4.3.2. Fleet Value 

Fleet value is correlated with fleet size (Figure D.3) and is a significant predictor of 

enterprise value (Figure D.4). Fleet value is calculated as the sum of the net asset values of all 

the rigs in a firm’s fleet at the time of evaluation, where net asset value is an estimate of a rig’s 

net earnings potential over its estimated lifetime based on assumed future utilization and 

dayrates. Firms below the regression line are undervalued; firms above the regression line are 
42

overvalued and with the exception of Seadrill and Transocean, the enterprise value fits the 

relationship closely. The size of a firm’s asset base is correlated with its revenue base and thus 

enterprise value. A large asset base implies a platform for sustainable revenues and correlates to 

the diversity of the product line (Speer et al., 2009). 

Table D.4 shows firm enterprise value as a percentage of fleet net asset value for selected 

publicly traded contractors between 2010 and 2012. For most firms, enterprise value varied 

between 80 and 120% of net asset value. Valuations are market dependent and vary with market 

conditions, rig specifications, customers, and other factors. For example, Rowan exhibits a 

valuation between 60 and 90% of its net asset value because it is a jackup specialist with a large 

proportion of its operations in the low-dayrate Persian Gulf and U.S. GOM. By contrast, 

Seadrill’s enterprise value is over 200% of net asset value due to the high-spec nature of its fleet 

and its focus on Southeast Asia and the North Sea where utilization rates are high and dayrates 

command a price premium. 

4.3.3. Debt 

The cost to construct an offshore drilling rig is substantial and the capital requirements for 

maintain a fleet can also be high. As a result, contract drillers often show negative free cash flow 

during periods of construction or major fleet enhancement. Figure D.5 shows the quarterly debt 

to market capitalization ratio over time for two firms (Seadrill and Songa) that have been active 

in newbuilding and in the secondhand market over the 2008-2011 period. 

In 2008, Songa’s debt to market capitalization was relatively high because it had used debt to 

finance the purchase of rigs and had a limited cash flow; its 2008 earnings were approximately 

$200 million compared to a total debt of approximately $1 billion. Songa’s debt load declined as 

the company used earnings to pay off debt, such that by late 2010, Songa’s debt had declined to 

approximately $500 million. In 2011, Songa entered into a new credit facility to finance the 

construction of new rigs, increasing its debt to market capitalization ratio. 

By contrast, Seadrill’s debt as a proportion of market capitalization remained relatively stable 

from 2008-2011, even as the firm’s debt load grew from $6 billion in 2008 to $10 billion in 

2011. Instead of using cash to pay off debt, Seadrill has spent cash on acquisitions and 

newbuilds; strong current and projected future earnings have allowed the firm to maintain a high 

market capitalization and an acceptable debt ratio. 
43

4.4. PRODUCT DIFFERENTIATION

Drilling contractors maintain a portfolio of assets specific to their business strategy and 

capacity to access capital markets. Generalists maintain a geographically and technically diverse 

fleet, while specialists are smaller firms that cannot simultaneously compete in all regions and 

markets and specialize to build customer relationships and capitalize on economies of scale. 

There tends to be variation in demand trends across geographic regions and water depth and 

a diverse fleet allows contractors to respond to changing industry conditions. A fleet diversified 

by rig type and specification is able to adjust to market upswings and weather industry 

downturns. High quality and new rigs generally continue to operate (albeit at a lower dayrate) 

during industry downturns. Companies that provide commoditized services (e.g. shallow water 

jackups) are exposed to greater competitive pressures and lower barriers to entry. 

Transocean, Noble, Diamond and ENSCO are generalists active in a large number of markets 

and regions, while most other firms specialize to a greater degree (Tables D.5 and D.6). Seadrill 

is the only large-cap specialist and focuses on the high spec markets in the North Sea, Southeast 

Asia and Brazil. All large cap drilling contractors received a majority of their 2011 revenues 

from the floater markets, and despite significant jackup fleets, the floater segment accounted for 

85 and 93% of revenues for Transocean and Diamond, respectively. For Noble, ENSCO and 

Seadrill, floaters accounted for approximately 60 to 65% of revenues. 

Smaller firms such as Hercules, Rowan, Atwood, and Songa are more specialized. Hercules, 

Rowan and Songa each specialize in a single water depth market; Atwood is less specialized and 

maintains a diverse fleet, however, most of its revenues are generated by its Asian floater fleet. 

4.4.1. Regional Concentration 

Drilling contractors concentrate assets in regions to capitalize on economies of scale through 

the reduction of administrative costs, build customer and governmental relationships, and match 

fleet and regional characteristics. There are advantages to this approach, but political risk 

increases with concentration, and to manage this risk, geographic diversity may be a business 

strategy. 

Table D.7 shows the revenues by region for large publicly traded drilling contractors in 2011. 

Brazil is a major source of revenue for all five large-cap firms, and the U.S. GOM market is a 

significant source of revenue for all firms. With the exception of Hercules, the North Sea is also 

an important source of revenue for all firms. Diamond is particularly dependent on the Brazilian 

market while Hercules is dependent on the U.S. GOM market; for each firm a single market 

accounts for approximately half of total revenues. Since the U.S. GOM shallow water market is 

in decline and Petrobras has ordered a large number of floaters, this strategy may negatively 

impact these firms’ valuations. All other firms are more geographically diverse and no region 

accounts for more than 30% of revenues. 
44

4.4.2. Customer Concentration 

Due to contractor’s regional concentration, a small number of E&P firms frequently make up 

a large proportion of a contractor’s revenue. This can create risk for the firm because the loss of 

a single client can eliminate a major source of revenue. Table D.8 shows the major customers of 

selected contractors in 2011. Consistent with the importance of the Brazilian market to firm 

revenues, Petrobras is a significant customer for several firms including Diamond. 

NOCs and IOCs are the largest customers for nearly all firms consistent with their size. 

Transocean is particularly diverse and its largest customer (BP) only accounts for 10% of 

revenues. The importance of NOC customers including Petrobras, Pemex and Saudi Aramco is 

notable. Given the increasing role state-owned drilling contractors play in the market, these 

NOCs may shift towards in-house drilling contract services. 

4.4.3. Age 

Drilling contractors are differentiated by the age of their fleets. Figure D.6 shows the fleet 

age of selected contractors along with the proportion of their fleet that was inactive in December 

2010. There is a positive relation between fleet age and the proportion of active rigs, indicating 

that firms with old fleets are more likely to stack rigs while firms with young fleets are more 

likely to experience high utilization. Both Hercules and Diamond have old fleets, but Diamond’s 

rigs experienced higher utilization than Hercules due to the upgraded nature of many of 

Diamond’s rigs and different customer and geographic base. Hercules depends heavily on U.S. 

jackup revenues and the decline in the GOM shallow market has led to a high degree of 

unutilized rigs; Diamond is more diverse and operates jackups and floaters internationally. 

Figure D.7 shows the average dayrates of jackups and floaters by rig delivery year. All 

jackups or floaters delivered in a given year were grouped together and their dayrates averaged 

over the 2000-2010 period. There is a significant correlation between rig age and average 

dayrates implying that firms that operate newer rigs are likely to receive higher dayrates than 

firms that specialize in older rigs. 

4.4.4. Specification and Water Depth 

Figure D.8 categorizes the fleets of leading public firms into high and low spec jackups and 

floaters. Active and stacked rigs are included in the count, but rigs under construction are not. 

High-specification jackups are defined as those capable of drilling in 350 ft or greater water 

depths or capable of operating in harsh environments. High-specification floaters are capable of 

operating in at least 7,500 ft of water or in harsh environments. Transocean, Noble, Ensco, and 

Diamond are the only drilling contractors to own units in every rig classification. In contrast, all 

of Seadrill’s units are high-spec, and nearly all of Hercules’ units are standard jackups.

4.4.5. Net Revenue by Rig Class 

Table D.9 shows average daily operating expenses, dayrates and net revenue by rig class for 

Transocean and Diamond in 2011. Operating expenses include all of the costs associated with 

operating and maintaining a rig over the course of a year, including active costs, stacked costs, 

and maintenance costs. Net revenue is computed as the difference between dayrate and operating 

cost per rig class and reflects the average daily revenue from operation. Expected net revenue is 
45

determined on an annual basis as the product of dayrate and utilization rate, minus the operating 

costs. 

For Transocean, ultra-deepwater and harsh environment floaters are particularly profitable 

due to high utilization and a large difference between the dayrate and the daily operating 

expense. High-specification jackups were the only market segment with a negative expected net 

revenue in 2011. Diamond’s deepwater fleet experienced higher dayrates than its ultra-deepwater 

fleet in 2011, and was Diamond’s most lucrative market. Rigs in the mid-water market generated 

approximately $40 million per rig for both firms, and the jackup segment was only marginally 

profitable. 

4.5. NEWBUILDING STRATEGIES

4.5.1. Speculative Newbuilding 

Firms invest in newbuilding when the estimated net cash flows exceed internal investment 

criteria and capital budgets and credit markets allow investment. Newbuilding represents a 

significant capital expenditure while future dayrates and utilization rates are uncertain. 

Therefore, newbuilding is a high risk investment and firms may undertake strategies to reduce 

this risk. Three strategies have been employed by industry: initial contract, price discount, and 

speculation. Additionally, in some cases, an E&P firm will enter into a joint ownership 

arrangement for a newbuild rig. In the private sector this is relatively rare and is limited to 

extremely high-risk projects such as Shell’s construction of an Arctic drillship with Frontier 

Drilling. Among state-owned drilling contractors and NOCs, such arrangements are more 

common. 

Initial Contract 

Under an initial contract strategy, contractors require an initial long-term contract from an 

E&P firm before investment in order to secure cash flows during the early life of the rig. Bob 

Rose, former CEO of Global Marine, summarizes the strategy: “No newbuilds without a user 

contract in hand (DeLuca, 2001).” Since future cash flows are discounted in decision-making, 

cash flows in the near term are more valuable than cash flows in the future. Without an initial 

contract, a drilling contractor may experience a negative net cash flow in the first years after a rig 

is delivered and this can have a significant negative impact on the profitability of the investment. 

Proponents of an initial contract approach argue that building speculatively provides a signal 

to E&P firms that rig availability will increase in the future which reduces the motivation of E&P 

firms to commit to long-term contracts. Additionally, building without an initial contract adds 

supply that is not demanded, which may lead to industry-wide reductions in dayrates (DeLuca, 

2001). Transocean is the largest firm in the industry and the most likely to be impacted by fleetwide reduction in utilization or dayrates, and as a result, is the primary advocate of the initial 

contract approach (DeLuca, 2001; Anderson et al., 2011). 

E&P firms are only likely to build against a contract when market conditions are so tight that 

they are unsure they will be able to contract capacity (DeLuca, 2001). As long as one or more 

firms are willing to build without an initial contract, E&P firms will not need to enter into 
46

construction contracts and initial contracts will be rare. In recent years, independents and IOCs 

have rarely entered into initial contracts for newbuilds, but initial contracts are more common for 

NOCs. 

Price Discount 

Under a price discount strategy, firms invest counter-cyclically during periods of low 

newbuild prices to reduce the magnitude of the risk. Stedman Garber, former CEO of Sante Fe, 

summarizes the position “Counter-cyclical is the best time to build, contract or not (DeLuca, 

2001).” The goal of a price discount strategy is to minimize cost rather than attempt to match 

supply and demand, and proponents of a price discount strategy argue that the benefits of an 

initial contract do not justify higher capital costs. Lower capital costs allow companies to be 

more competitive in the long run because the capital cost is locked in for the life of the rig. While 

there is a risk that the rig will be under-utilized after delivery, it is likely that the newbuild rig 

will be utilized since they are preferred in the market, but at the cost of utilization and dayrates 

elsewhere in the fleet. 

Speculation 

During periods of high utilization and dayrates, firms enter into newbuild contracts without 

an initial contract with the expectation that the rig will win work during the construction period. 

This is a high risk strategy because there is a risk that the rig will be unutilized or utilized at a 

low dayrate after delivery. During newbuild cycles, speculation is the dominant strategy, and 

since newbuild cycles are the primary source of fleet expansion, speculative newbuilding is an 

important source of new rigs. A price discount strategy is differentiated from a speculative 

strategy in that proponents of a price discount strategy would not build speculatively during the 

peak of a newbuild cycle. Thus, price discounting is a popular strategy only at the beginning of a 

newbuild cycle (DeLuca, 2001). As of Jan 2012, 78% of jackups, 65% of semis and 62% of 

drillships under construction had been ordered without an initial contract. 

4.5.2. Firm Size 

Firms differ in newbuilding strategies and smaller firms spend a larger proportion of their 

value on newbuilding than larger firms. Enterprise value was used to proxy company value, and 

the fraction of enterprise value invested in newbuilding was determined by dividing annual 

newbuild expenditures by total enterprise value over the 2005 to 2011 period. This value was 

then plotted against the average enterprise value for each firm over the time period (Figure D.8). 

The natural logarithm was used because of wide differences in values. 

The data suggest that as the size of the firm increased, the proportion of firm value invested 

in newbuilding expenditures over 2005-2011 decreased. Over the recent newbuilding cycle, large 

firms such as Transocean and Diamond have invested relatively little in newbuilding, while 

small and midsized firms such as Scorpion, Vantage, Seadrill and Aker have invested heavily. 

Instead, Transocean has used cash to finance acquisitions which is an alternative strategy to grow 

and diversify their fleet, while Diamond typically pays large dividends to shareholders. 
47

4.6. MARKET STRUCTURE

Market structure characterizes the level and type of competition among rig companies and 

determines their power to influence prices for their service. If the industry is perfectly 

competitive, drilling contractors cannot raise prices above the marginal cost of operation without 

losing market share to their competition. According to basic microeconomic theory, perfectly 

competitive industries are characterized by unrestricted entry and exit of firms, large numbers of 

firms, and undifferentiated (homogenous) services being offered (Perloff, 2008). Here we 

consider whether the offshore drilling market is competitive based on a qualitative examination 

of these factors. 

4.6.1. Mergers and Acquisitions 

A number of mergers and acquisitions have occurred over the past two decades which have 

consolidated the industry (Figure D.10). Recent mergers and acquisitions include ENSCO and 

Pride in 2011, Global Santé Fe and Transocean in 2007, Transocean and Aker in 2011, Noble 

and Frontier in 2010, and Seadrill and Scorpion in 2010. 

Much of the impetus behind industry consolidation is the competitive advantage associated 

with a larger capital base and greater asset diversification. Size implicitly incorporates a degree 

of diversification by geography, rig class, rig quality, contract duration and customer base. Large 

companies benefit from greater asset diversification, financial resources and liquidity, and 

economics of scale, and can withstand shocks or market downturns better than smaller firms and 

tend to be correlated with other characteristics such as market power and diversification (Cabral, 

2000). Mergers are a critical growth strategy for all large-cap drilling contractors and are a 

means to renew and upgrade their fleets without entering into newbuild construction (Lee and 

Jablonowski, 2010). 

4.6.2. Barriers to Entry 

Significant barriers to entry exist in the offshore drilling market. Over the past decade, 

newbuilt jackups cost between $150 and $300 million while newbuilt floaters cost between $500 

million and $1 billion. Firms entering the industry typically build three or more rigs to take 

advantage of economies in the construction process and in administrative costs. It is difficult to 

raise this amount of capital to enter a mature and competitive industry. New market entrants that 

are not financed by a government initially raise capital from a variety of private sources and 

institutional investors (e.g. hedge funds or private equity firms) and may issue an initial public 

offering. Following public placement, firms may gain access to loans through debt markets. For 

established firms, the issuance of bonds is a major source of low-cost capital (Norton Rose, 

2011).

Successful entry also requires significant human capital. A high degree of specialized 

knowledge is necessary in management and operations positions which are only available to 

those already in the industry or recently retired. Drilling is an intangible service and contractors 

are difficult to evaluate without prior experience, which creates customer loyalty and may make 

operators unwilling to hire new contractors. 
48

4.6.3. Consolidation 

Figure D.11 depicts consolidation in the offshore drilling industry between 1984 and 2010. In 

the 1980’s, there were approximately 160 drilling contractors and the top 10 firms owned about 

35 to 40% of the total rig fleet. Between 1989 and 2004, the industry experienced a prolonged 

downturn and consolidation eliminated nearly half of the contractors. Since 2004, the number of 

firms has increased and new entrants have emerged to take advantage of high dayrates and 

greater access in regional markets. The top 10 drilling contractors in 2010 own slightly more 

than half of the world fleet. 

4.6.4. Measures of Industry Concentration 

Economists use a variety of measures to assess the concentration of a given industry. 

Common measures include four firm concentration ratios (CR4), eight firm concentration ratios 

(CR8), and Herfindahl-Hirschman indices (HHI). CR4 and CR8 measure the percentage of sales 

accounted by the top four and eight firms in the industry. The HHI is the sum of the squared 

market shares of firms in the industry. 

These measures of industry concentration are reported in Table D.10 for the offshore drilling 

market in 2010 using contracts (not sales) as the evaluation unit. Each contract was considered 

one unit of market share. The floater markets are more concentrated than the jackup markets and 

the top four firms account for over 50% of the jackup market and nearly 70% of the semi and 

drillship market. The eight largest firms account for approximately 80 to 90% of the industry in 

all three markets. The market is far more concentrated when measured by contracted rigs 

because large drilling contractors are frequently more successful in maintaining high utilization 

than smaller firms with a few rigs. Market concentration declines when floaters are considered as 

a single market. 

Figure D.12 shows the six-month moving average of the monthly market concentration in the 

jackup and floater markets from 2001 to 2010. HHI was calculated in each month assuming that 

any rig under contract in that month was one unit of market share. Over the period, global market 

concentration remained relatively stable for both rig types. In the jackup market, market 

concentration increased in the U.S. GOM as several firms left the region, but concentration 

declined in South East Asia and the Persian Gulf as new firms entered in response to growing 

demand. Market concentration was higher in the floater market than the jackup market. Market 

concentration declined in the West African and Southeast Asian floater markets, but remained 

relatively stable in the North Sea, GOM and global markets. 

Accepted criteria have been established for determining market structure based on the HHIs 

for use in horizontal merger analysis (USDOJ and FTC, 2010). According to these criteria, 

industries with HHI below 1,000 are considered unconcentrated (i.e. more competitive); 

industries with HHIs between 1,000 and 1,800 are considered moderately concentrated (i.e. 

moderately competitive); and industries with higher HHIs are considered heavily concentrated. 

Based on these criteria, the offshore drilling jackup market continues to be globally 

unconcentrated even after an increase in merger activity, while the floater market is moderately 

concentrated. On a regional basis a higher degree of concentration is apparent. 
49

4.6.5. Firm Competition 

Firms can influence prices for their services through differentiation. By differentiation 

through technology, safety record, and crew experience, and using marketing to establish 

company loyalty, drilling contractors can raise their prices above marginal cost without losing 

market share to competitors. However, by the nature of their operations drilling rigs are quite 

homogenous, and there is little substantive difference between rigs of the same generation and 

across generations when upgraded. While there may be some instances where service 

differentiation is important, these are expected to be isolated. Overall, the market is commoditylike in nature which impedes the ability of firms to differentiate their products. 

The offshore drilling rig industry is characterized by the production of largely similar 

products (wells). Barriers to entry, market size and other factors impact competition among 

firms, but it is difficult to quantify the magnitude of this effect and it seems unlikely that 

individual companies are able to significantly influence market prices. Overall, the market is 

considered competitive with potentially transitory non-competitive periods in certain 

concentrated regions or specialized markets. 

4.7. CONCLUSIONS

The contract drilling market is dominated by a small number of publicly traded firms with 

Transocean, Seadrill, Noble, ENSCO, and Diamond being the major players and controlling 

about 40% of the total fleet and 50% of the floater fleet. Fleet value and revenue are good 

predictors of the enterprise value of publicly traded firms. 

Firms specialize by rig class, region and customer, but all five of the largest contractors in 

2011 generated most of their revenues from the floater market, and for Diamond and Transocean, 

floaters generate much greater net earnings per day than jackups. Nonetheless, these firms 

continue to operate in the shallow water market to foster fleet diversity. 

Three newbuilding strategies were identified and speculation is the most popular method for 

fleet expansion despite the higher risk. Over the 2005 to 2011 newbuild cycle, smaller firms 

invested a larger portion of their enterprise value in newbuilding than larger firms, while larger 

firms were more likely to grow through mergers and acquisitions. 

Merger and acquisition activity is common among the largest players in the industry and 

generates concerns about market concentration and competition. Despite the size of the largest 

players, the jackup market is not concentrated globally while the floater market is moderately 

concentrated. 
51

5. EMPIRICAL ANALYSIS OF FACTORS IMPACTING DAYRATES 

The offshore drilling market is segmented by geographic region and rig class and varies with 

both regional and global market conditions over different periods of time. In this chapter we

evaluate the factors that impact rig dayrates. Our approach is to consider single factor effects 

over select categorizations and time periods. We motivate the analysis through hypothesis and 

test the validity of each hypothesis using empirical data. We examine the impacts of oil prices on 

demand and evaluate the relationship between dayrates and oil prices, utilization rate, rig 

specifications, contract length, E&P ownership, contractor size and well type. We find dayrates 

are positively correlated with oil prices, utilization rates, rig specifications, and contract length. 

NOCs pay higher dayrates than IOCs, and appraisal drilling is more expensive than 

developmental or exploratory drilling. There is no evidence that large firms such as Transocean 

can utilize market power to command premium dayrates. 

5.1. HYPOTHESES

A large number of factors have the potential to influence dayrates, and in the popular press 

and among industry experts, a body of “common knowledge” has developed over the years. This 

common knowledge has not been empirically verified in publicly available or peer-review 

publications (but see Rankin, 1981), and as a result, the veracity of the claims and their analytic 

basis remain subject to scrutiny. The purpose of this analysis is to critically review basic 

expectations of selected claims and to quantify observed differences and trends. We evaluate 

trends and correlations over a multiyear period and offer reasons for the hypothesis stated. Some 

of these reasons can be tested, but many cannot, so our observations are tempered by the 

availability of data and factor analysis. 

We evaluate the following hypotheses: 

H1. Demand for drilling services is positively associated with oil prices. 

H2. Dayrates increase with increasing oil prices. 

H3. Dayrates and utilization rates are positively correlated. 

H4. High specification rigs charge higher dayrates than low specification rigs. 

H5. Long-term contracts provide a price premium over short-term contracts. 

H6. National oil companies pay higher dayrates than other companies. 

H7. Large drilling contractors command higher dayrates than smaller contractors. 

H8. Appraisal drilling programs pay higher dayrates than exploratory or 

developmental drilling. 

Hypotheses H1 to H4 evaluate basic assumptions widely reported in the industry. In 

hypothesis H1, rig demand is the dependent variable; in all other hypotheses, the dayrate is the 

dependent variable. Hypotheses H5 to H8 identify factors that may contribute to the variation in 

dayrates between and within regions and when time is included as a variable. These hypotheses 

are less obvious and require greater scrutiny. Drilling contractors frequently seek a mix of long 

and short-term contracts to balance risk, and hypothesis H5 evaluates the costs of this strategy. 

For political reasons, NOCs are expected to overinvest in drilling relative to IOCs, and this is 

evaluated in hypothesis H6. Hypothesis H7 examines the ability of firms to use market power to 
52

influence prices. Appraisal drilling is more technically challenging than exploratory or 

developmental drilling and may be associated with a dayrate premium which is tested in 

hypothesis H8. 

5.2. METHODOLOGY

5.2.1. Data Source 

Data from 7,123 rig contracts between January 1, 2000 and December 31, 2010 were 

obtained from RigLogix. RigLogix uses surveys and contact with industry personnel to assemble 

dayrate data. Data is reported on a contract basis and includes both contract variables (dayrate, 

contract start date, contract duration, region) and rig variables (rig type, rig delivery date, rig 

maximum water depth, rig maximum drilling depth). Data on the number of active rigs and 

regional utilization rates were employed from a separate RigLogix dataset. Data on Brent oil 

prices was obtained from the Energy Information Administration. Brent crude is the global 

benchmark of oil prices and is closely related to offshore production. 

5.2.2. Categorization 

Individual contract records were treated as independent data points. Activity was considered 

in five regions: the U.S. Gulf of Mexico (GOM), North Sea, Persian Gulf, West Africa and 

Southeast Asia. Each region was subdivided into jackup and floater classes. The floater class 

includes semisubmersibles and drillships. Jackup and floater classes were delineated by water 

depth, ownership, customer, and time period. The number of contracts in the dataset by region 

and rig class is shown in Table E.1. The U.S. GOM has the largest number of contracts in the 

jackup market during this time period, and along with the North Sea, is the largest floater market. 

In total, the U.S. GOM is responsible for over half of the number of contracts from 2000-2010, 

reflective of the dominant position of the U.S. GOM’s contribution to total wells drilled during 

the period. 

Offshore drilling contracts correspond to the number of wells drilled, but the correspondence 

is not perfect because of differences in contract duration, work requirements, well complexity, 

and other factors. Wells drilled is a directly observable quantity, whereas drilling contracts may 

be written for multiwell programs, workovers, completions, sidetracking, etc. and are a better 

representation of revenue generation. The number of contracts provides a direct indicator of the 

demand for drilling rigs by class type, region, water depth, time period, and customer, and 

provides useful and direct information on the status of the rig market. 

The five regions selected are the largest regions with competitive markets. Brazil is an 

important floater market but is monopolized by a single E&P firm (Petrobras) and was therefore 

excluded. Within and across regions, water depth, drilling depth, and rig class are employed to 

further delineate activity trends; rig classes partially correspond to water depth categories. 

Demand trends for shallow water, midwater, and deepwater fixtures tend to vary by region, and 

in some regions, one or more water depth categories are not present (e.g. the Persian Gulf has no 

deepwater segment) which explains the absence of rig classes. All the other regions have a full 

range of water depth intervals. 
53

The time period of analysis is an important categorization since results depend on the period 

selected. For example, from 2004 through 2006, oil prices and dayrates rose significantly, and as 

a result of these changes, market conditions in the 2000 to 2005 and 2006 to 2010 periods differ 

in significant ways. Table E.2 depicts the average dayrate by region in the pre- and post-2006 

periods. In the jackup market, the increase in dayrates pre- and post-2006 varied between regions 

with increases being modest in the U.S. GOM (68%) and higher in Southeast Asia (135%). In the 

floater market, the change in dayrates in pre- and post-2006 periods was more pronounced, and 

three of the four floater markets increased by approximately 200%. 

While dayrates changed over the 2000 to 2010 period, the relative positioning of the regional 

markets remained stable. The U.S. GOM was the least expensive jackup market in both the 2000 

to 2006 and 2006 to 2010 periods, followed by the Persian Gulf. West Africa and Southeast Asia 

experienced similar dayrates in both periods, while the North Sea was consistently the most 

expensive jackup market. In the floater market, Southeast Asia was the least expensive in both 

time periods, while West Africa was the most expensive market. 

Models of market behavior and empirical analysis are unlikely to capture sudden and 

dramatic changes in dayrates. Whenever possible, we used data from the entire time period to 

maximize sample size and limit assumptions. However, in the case of utilization rates, there was 

a notable difference in the pre and post-2006 data, and only the post-2006 data was examined. 

5.2.3. Approach 

Dayrates were inflation adjusted to 2010 using the U.S. BLS annual producer price index for 

all finished goods and the start year of the contract. The inflation adjustment allows for 

comparison across the decade but may introduce bias since the U.S. producer price index cannot 

capture all inflationary pressures in the industry. Monthly average dayrates were applied in the 

analysis. In these cases, the dayrate in a given month was the average of the dayrates of all 

contracts for which drilling began in that month, and not the average of all active contracts in the 

month (Figure E.1). Data on Brent oil prices were inflated to 2010 values. 

Linear regression and analysis of variance were used to test hypotheses. When multiple 

comparisons were performed, the Tukey-Kramer method was used (Off and Longnecker, 2001). 

All variables were tested for serial correlation, and when present, the AUTOREG procedure in 

SAS 9.2 was used. The order of the autocorrelation varied depending on the results of a stepwise 

autocorrelation.6

 In cases in which data were not serially correlated, ordinary least squares (OLS) 

regression was employed. When linear regression was performed, models were evaluated with 

and without logarithmic transformation. Transformed models generally performed better than 

non-transformed models and were adopted, consistent with standard econometric techniques 

(Ramanathan, 1998). 

 

6 The order of an autocorrelation is the number of previous periods used for the prediction of the error term. For 

example, in a first order autocorrelation, the error term μt in the standard linear regression model (Yt= β0 + β1Xt + μt) 

is dependent on the error in the previous period (μt-1). In a second order autocorrelation, the error term is dependent 

on the error in the two previous periods. 
54

Moving average oil prices and utilization rates are used in several models and correlated 

against rig supply and dayrates. Moving averages smooth out data set and are integrative in the 

sense that they are computed over a period of time, and thus include information on the entire 

period. Offshore drilling is capital intensive and development projects tend to be long, multiyear 

projects, relative to the short-term cycles of exploration. The data set contains exploration and 

development well types. 

5.3. DEMAND FOR DRILLING RIGS IS POSITIVELY ASSOCIATED WITH OIL PRICES 

As oil prices increase, the net income and capital budgets of E&P firms increase and drilling 

activity will respond. Studies have found a positive relationship between measures of drilling 

effort and oil prices with elasticities often greater than one (reviewed in Dahl and Duggan, 1998; 

Ringlund et al., 2008; Cole, 1995). 

To estimate the elasticity of demand with respect to oil prices, we built a regression model 

using average monthly oil prices and the 3, 6, 9, 12, 18, and 24 month moving average of oil 

prices as predictors of the total number of rigs under contract in a given month. We consider all 

active rigs in all offshore basins and evaluate jackups and floaters separately. Figure E.2 shows 

the relationship from 2001 to 2011. Models were evaluated with and without logarithmic 

transformations. The natural logarithm of the dependent and predictor variables provided the best 

fit. 

For jackups, the best model was given by: 

ln(Nt) = 4.2 + 0.23 * ln(Oil12), R2= 0.92.

For floaters the best model was given by: 

ln(Nt) = 2.0 + 0.64 * ln(Oil24), R2= 0.97,

where Nt is the number of active rigs in month t and Oilk is the moving average of the oil price 

over the previous k months. Both models are first order autoregressive and the R2 values are high 

and the coefficients statistically significant (p < 0.05) and positive for both classes. For jackups, 

the 12 month moving average provides the best fit, and for floaters, the 24 month moving 

average is a better predictor than any shorter duration moving average. These results suggests 

that rig activity responds slowly to changes in oil prices, consistent with the long lead times 

required for offshore drilling programs. 

The elasticity of rig activity with respect to the moving average of oil prices was 0.23 for 

jackups and 0.64 for floaters. This is lower than the elasticity found for the global onshore and 

offshore rig fleet cited in previous studies and suggests that for every 1% increase in the moving 

average of oil prices, the number of working rigs increases by less than 1%. The lower elasticity 

in offshore rig activity is expected because offshore development is more expensive and risky 

than onshore development and occurs over longer development cycles encouraging E&P firms to 

act more conservatively and respond more slowly to changes in oil prices. This same rationale 

partially explains why the number of active floaters is correlated with a larger period of oil prices 
55

than jackups, since deepwater is associated with longer and more expensive development than 

shallow water regions. 

When regions were considered separately, the trends remained the same but the strength of 

the relationships declined for both jackups and floaters, and in most cases, was no longer 

significant. This suggests that at the global level, oil prices are adequate predictors of demand, 

but at the regional level, local factors such as geologic prospectivity and development cycles 

play a more important role. Oil prices are a global metric and when oil prices rise, global demand 

is stimulated, but the regional distribution of that demand is determined by local factors such as 

licensing, regulation, customer base, and prospectivity. 

5.4. DAYRATES INCREASE WITH INCREASING OIL PRICES 

Oil prices are a widely recognized driver of activity in the upstream sector since drilling is 

the only means to increase supply and capture the economic benefit of high prices. Increases in 

oil prices increase demand for drilling services and are expected to lead to increases in dayrates 

for all other things equal. 

Figure E.3 shows the relationship between global average monthly jackup and floater 

dayrates and Brent oil prices between 2000 and 2010. For both rig classes, there is a cluster of 

data between $40 to $80 oil prices which corresponds to the period following the oil price 

declines of mid to late 2008. During this period, dayrates did not move as rapidly as the 

commodity price fluctuations and suggests that rapid shifts in the commodity markets are not 

immediately reflected in dayrates. 

An autoregressive model was used to estimate price elasticity in jackup and floater dayrates 

over the time period 2000-2010. For both rig classes, the oil price and 3, 6, 9, 12, 18, and 24 

month moving averages were used as predictor variables. Models with and without logarithmic 

transformations were evaluated, and models with logarithmic transformations provided a better 

fit than non-transformed data. 

For jackups, the best model was a second order autoregressive model: 

ln(DRt) = 7.8 + 0.87 * ln(Oil12), R

2

= 0.91,

and for floaters, the best model was a first order autoregressive model: 

ln(DRt) = 6.8 + 1.4 * ln(Oil24), R

2

= 0.93,

where DRt is the average dayrate in month t and Oilk is the moving average of the oil price over 

the previous k months. As expected, dayrates are positively related to oil prices, and the 

coefficients of the oil price term are positive regardless of the length of the moving average 

employed. The 12 month moving average oil price was the best predictor for jackup dayrates, 

while the 24 month moving average was the best predictor of floater dayrates. These periods are 

the same as the demand model in the previous section and show that jackup dayrates respond 

more rapidly to changes in oil price than floater dayrates due in part to the shorter duration of the 

development cycles and the integrative effects of the moving average. Jackup contracts also tend 
56

to be of shorter duration than floater contracts which partially explains the differences in time 

periods. 

The elasticity of dayrates with respect to oil prices was 0.87 for jackups and 1.4 for floaters 

indicating that floater dayrates are more sensitive to changes in oil prices; however, this 

difference reflects the duration of the moving averages and cannot be used for such an inference. 

Since oil prices in the floater model are averaged over a longer period, they tend to be more 

stable, and a 1% increase in the 24 month moving average signifies a greater shift in market 

conditions than a 1% increase in the 12 month moving average. Thus, the difference in elasticity 

between rig classes should be interpreted with caution. 

Model coefficients were similar when regions were compared separately. For jackups, 

elasticities varied from 0.7 in the Persian Gulf to 0.95 in the U.S. GOM, and model fit declined 

slightly in all regions except the U.S. GOM, likely due to the reduction in sample size. For 

floaters, regional elasticities varied from 1.0 (West Africa) to 1.2 (Southeast Asia). Therefore, 

while oil prices are not a good predictor of regional demand, they are an adequate predictor of 

dayrates at the regional level because dayrates are more strongly correlated between regions than 

the number of active rigs. 

5.5. DAYRATES AND UTILIZATION RATES ARE POSITIVELY CORRELATED

When regional utilization is low, the supply of stacked units is large relative to demand and 

contractors bid aggressively to win work, increasing competition and lowering dayrates. When 

utilization rates are high, there is more competition among E&P firms for access to contract 

drilling, and contractors can negotiate more favorable terms, increasing dayrates and providing 

signals to the market that additional capacity can be absorbed. 

The monthly utilization rate and dayrate in the U.S. GOM jackup market from 2000-2011 is 

depicted in Figure E.4. Other markets exhibited similar dynamics and are not depicted. There 

were no statistically significant relationships between utilization rate and dayrate across the 

entire time period in any market or region, but in the post-2006 period, utilization and dayrates 

were correlated across all regions. Over longer time periods, other factors (e.g. newbuild 

deliveries) influence markets and may predominate. 

We regressed the dayrate and the 3, 6, 9, 12, 18, and 24 month moving average of utilization 

rate in each of the five jackup markets and the four floater markets in the post-2006 period using 

the functional specification: 

ln(DRt) = β0 + β1 ln(Ux),

where DRt is the average dayrate in month t and Ux is the x-month moving average of the 

utilization rate. Models with and without logarithmic transformations were evaluated, and 

models with logarithmic transformations provided a better fit than non-transformed data. 

The best models for floaters and jackups are shown in Table E.3. In most cases, statistically 

significant models were developed, however, the North Sea and Persian Gulf jackup models only 

explained a small proportion of the variation in dayrates, and no statistically meaningful 
57

relationship in the Southeast Asian floater market existed. All successful models contained a 12, 

18 or 24 month moving average predictor, and the moving averages in the jackup models were of 

shorter duration than those in the floater models. The floater models were autoregressive while 

the jackup models were not. 

The relationships between utilization and dayrates varied across regions. In the Persian Gulf 

and North Sea jackup markets, lower variation in utilization is the likely reason robust models 

could not be developed. The Persian Gulf and North Sea had the lowest variance in utilization 

rates which the models were unable to explain. One factor utilization-based models were 

adequate for explaining large changes in dayrates, but were unable to resolve more subtle 

differences. 

No significant relationship between utilization rates and dayrates was detected in the 

Southeast Asian floater market. The Southeast Asian floater market is significantly smaller and 

utilization rates are consistently lower than the other floater markets, and over the 2006-2010 

period, utilization rates in the region did not follow the other markets. The Southeast Asian 

market is in close proximity to several other floater markets (India, China, and Australia), and 

due to the highly mobile nature of semisubmersibles and drillships, it may be more meaningful to 

classify all four Asian markets into a single regional market. 

Figure E.5 illustrates the results of three predictive jackup models. As utilization rates 

increase, dayrates increase, and the rate of increase is higher in West Africa and Southeast Asia 

than in the U.S. GOM. In Southeast Asia, the relationship between utilization and dayrates is 

non-linear, while in the U.S. GOM and West Africa, the relationship is approximately linear (e.g. 

β1 ≈ 1). The results of the three statistically significant floater models are depicted in Figure E.6. 

The U.S. GOM and North Sea models are based on the 18 month moving average, while the 

West Africa model uses the 24 month moving average. All three models are non-linear, and the 

U.S. GOM model has the largest slope. 

5.6. HIGH SPECIFICATION RIGS CHARGE HIGHER DAYRATES THAN LOW 

SPECIFICATION DRILLING RIGS

Differences in rig specification lead to product differentiation in the market (Mascarenhas, 

1996). A number of rig specifications exist, but water depth and drilling depth are most critical in 

determining the ability of a rig to drill a given well (Harris, 1989; Robertson, 2003). As the water 

depth or target depth increases, the number of rigs capable of drilling declines, decreasing 

competition and increasing prices. For shallow water wells or shallow geologic formations, more 

advanced capabilities are usually not necessary. The time period is 2000-2010 and all geographic 

regions were consolidated into a single category. Statistically significant differences between 

categories are denoted by letters (e.g. categories marked “A” do not differ from other A’s, but do 

differ significantly from B’s, C’s, etc.).

5.6.1. Drilling Depth 

The average dayrates of jackups and floaters by drilling depth category is shown in Table 

E.4. For both rig classes, dayrates increase with increasing drilling depth capability. For jackups, 

rigs with drilling depth capabilities less than 15,000 ft did not have significantly different 

dayrates from rigs with maximum drilling depths of 15,000 to 20,000 ft, but all other drilling 
58

depth categories were significantly different. The lack of a significant difference is likely due to 

the small sample size in the less than 15,000 ft category. 

For floaters, rigs with capabilities less than 20,000 ft charged dayrates that were 

indistinguishable from those with capabilities of 20,000 to 25,000 ft, and rigs with capabilities of 

25,000 to 30,000 ft were indistinguishable from rigs with 30,000 to 35,000 ft drilling capacities. 

Rigs with drilling capabilities less than 25,000 ft, 25,000 to 35,000 ft and greater than 35,000 ft 

were significantly different and the direction of the differences matched expectations. 

5.6.2. Water Depth 

The average dayrates of jackups and floaters by water depth capability is shown in Table E.5. 

In both rig classes, deeper water depth capabilities are associated with dayrate premiums. For 

jackups, the premium is largest ($30,000 per day) between the 300 - 350 ft and 350 - 400 ft water 

depth categories. There is no significant difference between the 350 - 400 and greater than 400 

foot jackup categories which may reflect the small sample sizes.

For floaters, all four water depth categories are significantly different, but the biggest 

difference between categories is between the 5,000 - 7,500 ft and greater than 7,500 ft categories. 

In this case the premium is $80,000 per day while the premium among the other water depth 

categories is $23,000 to $34,000 per day. 

5.6.3. Station Keeping 

The average dayrates of independent leg cantilever versus slot or mat jackups and 

dynamically positioned versus moored floaters is shown in Table E.6. Dynamically positioned 

floaters are more expensive than moored floaters and independent leg cantilever jackups are 

more expensive than mat or slot units, and both differences are statistically significant. 

Contractors charge a premium of $113,000 per day for DP floaters and $35,000 per day for 

independent leg-cantilever units. The value of this premium over a 20 year operational life 

assuming 75% utilization rate and a 10% discount rate is $260 million for floaters and $80 

million for jackups. 

5.6.4. Regional Control 

Dayrates are higher for rigs with greater drilling depth capabilities, water depth capabilities 

and more advanced station keeping abilities, however, these results could be associated with the 

regions in which these rigs work. Table E.7 controls for regional variation and compares dayrates 

by drilling depth, water depth, and station keeping ability. To conserve sample size, rigs were 

divided into two water depth and drilling depth categories. 

Station Keeping 

In the U.S. GOM, independent leg cantilever units exhibited an average price premium of 

15,000 $/day relative to mat or slot units. In West Africa, the differences were also significant 

(43,000 $/day), but sample sizes were small. Dynamically positioned floater premiums ranged 

from $70,000 (West Africa) to $139,000 (Southeast Asia). 
59

Water Depth 

Except for Southeast Asia, all regions experienced higher dayrates for deeper water jackups, 

and the premium was relatively consistent across the period of analysis. The significant price 

difference between jackups with water depth capabilities less than and greater than 300 ft in the 

Persian Gulf is unexpected because the vast majority of the Persian Gulf is less than 300 ft deep 

and E&P firms cannot use the increased water depth capacity of these rigs. For floaters capable 

of operating in greater than 5,000 ft water depth, premiums ranged from $54,000 (West Africa) 

to $140,000 (U.S. GOM). 

Drilling Depth

Drilling depth was associated with increased dayrates in all regions, but the size of the 

premium varied significantly among jackup markets, from approximately 20,000 $/day in the 

U.S. GOM to nearly 70,000 $/day in the Persian Gulf. The low premium in the GOM may be due 

to the generally low dayrates, while the high price premium in the Persian Gulf may be 

associated with high and low-specification rig utilization in the market. For the drilling depth 

threshold of 25,000 ft, floaters that can drill greater than the threshold are associated with 

premiums ranging from $74,000 (West Africa) to $119,000 (U.S. GOM). 

High Spec Premium 

The daily value of the enhanced capability by category is depicted in Table E.8. Every 

$10,000 in increased daily revenue represents a $23 million increase in the total revenue 

generated by the rig over a 20 year period, assuming a 10% discount rate and 75% utilization 

rate. However, since high-spec rigs typically experience higher utilization than low-spec rigs, 

this is likely to be an underestimate of the actual revenue premium associated with high-spec 

rigs. 

5.7. LONG-TERM CONTRACTS ARE MORE EXPENSIVE THAN SHORT-TERM 

CONTRACTS 

Contractors generally seek a mix of long and short-term contracts to balance risk (Rowan, 

2009; OGFJ, 2007). Long-term contracts provide stable cash flows and guaranteed utilization, 

while short-term contracts increase the risk of stacking, but allow the contractor to take 

advantage of increasing markets and potential dayrate upswings (Moomjian, 2000). When 

dayrates are low, there is little incentive for a contractor to accept a long-term contract and shortterm contracts are preferred; as a result, we expect short-term contracts to exhibit lower average 

dayrates than long-term contracts. 

The mean duration of contracts was computed in each region over the period 2000-2010, and 

contracts were divided into those greater than and less than the regional mean duration and 

compared using a two tailed t-test. Table E.9 summarizes the results. In every region, short-term 

contracts had lower dayrates than long-term contracts, and in each case the difference was 

statistically significant. This suggests that E&P firms pay a premium for long-term contracts. For 

jackups, the difference between contract types ranged from 13% in Southeast Asia to 45% in the 
60

Persian Gulf. For floaters, the premium was higher and ranged from 25% in West Africa to 85% 

in the U.S. GOM. 

It is possible that the statistics vary temporally. If drilling contractors expect future price and 

utilization to decline, they may be willing to accept lower dayrates for long-term contracts. To 

control for the effects of time we separated the data into three periods: 2000-2004, 2005-2008 

and 2009-2010 to correspond with stable, improving, and declining market conditions. We 

assume that observed price changes reflect market participant expectations. If the dayrate 

premium for long-term contracts is dependent on market conditions, we expect there to be no 

premium for long-term contracts in the 2009-2010 period. 

Separating the data into three time periods, two rig classes and five regions provided 27 

comparisons. In 26 of 27 comparisons, longer than average contracts had higher dayrates than 

shorter than average contracts. This trend was only significant in 14 comparisons. There is no 

evidence that higher dayrates for longer term contracts are affected by the changing market 

conditions. 

5.8. NOCS PAY HIGHER DAYRATES THAN IOCS OR INDEPENDENTS

International Oil Companies (IOCs) and National Oil Companies (NOCs) may have different 

motivations for investing in drilling and may differ in their willingness to pay for drilling 

services. IOCs are motivated to maximize the present value of investments, whereas NOCs are 

motivated by both economic and political factors and may have a motive to subsidize domestic 

consumers, increase employment, or increase short-term revenue at the expense of long-term 

revenue (Hartley and Medlock, 2008). Each of these factors is expected to increase NOC 

exploration investment in the short-term and NOC willingness to pay for drilling services, 

increasing dayrates relative to IOCs or independents. 

We considered any firm in which the government is the controlling entity to be an NOC and 

included firms such as Statoil, Eni, DONG, Petronas, and Petrobras, as well as the NOCs of 

OPEC (Saudi Aramco, ADNOC, etc.). IOCs included ExxonMobil, Chevron, BP, Total, Shell, 

Marathon, and ConocoPhillips, and are usually integrated across the supply chain and have 

international development (Jaffe and Soligo, 2007; Eller et al., 2011; Inkpen and Moffett, 2011). 

All other firms were classified as independents.7

For jackups, NOCs paid on average approximately $25,000 more than IOCs and $40,000 

more than independents on a global basis between 2000-2010 (Table E.10). For floaters, NOCs 

paid on average $50,000 more than IOCs and $85,000 more than independents worldwide. All 

differences were statistically significant for both rig classes but the majority of contracts are for 

independents which could bias the data. 

 

7 Alternative classifications of NOCs, IOCs, and independents are possible. Eni is often classified as an IOC, 

but was considered an NOC because the Italian government owns a controlling share. Marathon was considered an 

IOC. Large E&P firms such as Anadarko and Apache were considered independents because they classify 

themselves as such. 
61

The trend observed in Table E.10 could be caused by regional or temporal factors. If NOCs 

are more active in expensive markets such as the North Sea, the same trends would be expected. 

From 2000 to 2010, NOCs became more active worldwide, particularly the jackup segment, and 

this coincided with an increase in dayrates. To control for the effect of time and regions, we built 

a linear regression model with the contract start year as a predictor variable and E&P firm type 

and region as indicator variables: 

DR = β0 + β1IND + β2IOC + β3YEAR + β4GOM + β5NSEA + β6AFRICA + β7PGULF,

where DR is the dayrate, IND is one if the E&P firm is an independent and zero otherwise, IOC 

is one if the E&P firm is an IOC and zero otherwise, YEAR is the contract start year, and GOM, 

NSEA, AFRICA, and PGULF are indicator variables that take the value one if the region is 

selected and zero otherwise. When the region was Southeast Asia, all regional indicator variables 

are zero. The Persian Gulf variable was not included in the floater model. 

The models for jackups and floaters are shown in Table E.11. After controlling for year and 

region, NOCs paid higher dayrates than independents and IOCs in the jackup market. NOCs paid 

higher dayrates than independents in the floater market, but the difference between NOC and 

IOC dayrates in the floater market was not significant. After controlling for temporal and 

regional factors, jackups employed by NOCs paid a dayrate premium of 17,000 $/day relative to 

independents and 11,000 $/day relative to IOCs. For floaters, NOCs paid a premium of $30,000 

relative to independents. While significant, these premiums are much lower than observed in the 

global sample, suggesting that time or regional differences account for a portion of the global 

premium. 

5.9. LARGE DRILLING CONTRACTORS ARE AWARDED HIGHER DAYRATES THAN 

SMALLER CONTRACTORS

Large drilling contractors may be able to use market power to achieve higher dayrates than 

their competitors and anecdotal evidence support these claims (Sheridan, 2008; Wethe, 2012; 

Lee and Jablonowski, 2010). Transocean is the largest drilling contractor and was a market 

leader throughout the decade. We compared the dayrates paid to Transocean to the dayrates paid 

to its competitors in each region and rig class from 2000 to 2010. Transocean received higher 

than average dayrates in the North Sea and U.S. GOM floater markets, however, when we 

controlled for the effects of rig water depth, the dayrate difference became non-significant. 

Similar results were achieved when the five largest drilling contractors (e.g. Transocean, 

Diamond, Noble, ENSCO, and Seadrill) were evaluated as a group. Thus, while large drilling 

contractors receive higher dayrates than their competitors in some regions, the effect appears to 

be due to the higher specifications of their fleets rather than the use of market power. 

5.10. DEEPWATER APPRAISAL DRILLING RECEIVES HIGHER DAYRATES THAN 

EXPLORATORY OR DEVELOPMENTAL DRILLING

In exploratory drilling, the primary goal is to find commercial quantities of hydrocarbons, 

while in development drilling, the goal is to produce hydrocarbons. During appraisal drilling, the 

goal is to define the characteristics of the reservoir, and as a result, appraisal drilling is 

considered more technically demanding than exploratory or developmental drilling (Knoring et 
62

al., 1999; Sah, 2010; Haskett, 2003). Information is a primary objective of delineation and 

because appraisal wells may later serve as production or injection wells, they are drilled carefully 

with special attention to their future utility. E&P firms may prefer to use higher-specification rigs 

for appraisal and a dayrate premium is expected. 

In the jackup markets, we found no significant differences in dayrates by well type on a 

regional or global basis. In the global floater market, appraisal drilling received a dayrate 

premium of approximately $80,000 compared to developmental and exploratory drilling, and 

there were no significant differences between exploratory and developmental drilling. 

It is possible that appraisal wells are drilled by more advanced rigs than developmental or 

exploratory wells, and this could explain the observed differences. We used floater maximum 

water depth category as a proxy for rig specification and separated floaters into mid-water (less 

than 3,000 ft), deepwater (3,000 to 7,500 ft) and ultradeep (greater than 7,500 ft) categories. The 

increased cost for appraisal drilling in floaters is robust across rig water depth capability (Table 

E.12). Appraisal drilling is always significantly more expensive than development or exploratory 

drilling, or both. As in the total sample, there is no clear pattern between costs for exploratory 

and developmental drilling. It is also possible that appraisal drilling has been more common in 

high cost regions such as the North Sea. When regions were compared separately, appraisal 

drilling was always more expensive than developmental or exploratory drilling, but the 

difference was only significant in the U.S. GOM and North Sea where the sample sizes were the 

largest (Table E.12). 

The observation of higher dayrates for appraisal drilling may suggest that drilling contractors 

require a risk premium for appraisal wells. If a drilling contractor damages a wellbore or 

otherwise provides inadequate well construction services, they are often contractually obligated 

to drill a replacement well at no additional cost to the E&P firm (Osmundsen et al., 2008). If 

appraisal wells are associated with a higher risk of failure, drilling contractors may require 

higher dayrates to undertake these programs. 

5.11. LIMITATIONS

We analyzed the effects of individual factors on dayrates by holding all other variables 

constant. In the real world, many factors interact simultaneously to impact dayrates, and it is 

reasonable to assume some interaction effects are present. When we aggregate rigs and analyze 

single factor trends over time, we do not consider the impact of interacting factors. For example, 

the analysis of contract duration did not account for rig specifications. High spec rigs may be 

more likely to get long-term contracts than low-spec rigs and this, rather than contract length, 

may account for the observation of higher dayrates for long-term contracts. In practice it is the 

impact of multiple observable and unobservable factors that determine dayrates. 

Sample size considerations limit the ability to make robust generalizations in factor analyses, 

especially in the floater markets. While the overall sample was large, the regional distribution of 

contracts was uneven, and only the U.S. GOM and North Sea had a sufficiently large number of 

contracts in both the jackup and floater markets. As a consequence, many comparisons within 

regions became insignificant. For example, when comparing dayrates for appraisal, exploratory, 

and development drilling within regions, the pattern of higher dayrates for appraisal drilling was 
63

consistent across regions, but significant differences were only observed in the U.S. GOM and 

North Sea. 

The regions were treated as independent, but in reality, the regions interact and exhibit a 

degree of correlation. If interactions are significant, it may be inappropriate to treat the regions 

separately. The U.S. GOM, North Sea and West African floater markets, particularly the drillship 

segment, are closely correlated in terms of dayrates, but exhibit differences in supply, utilization, 

and customer base, and the dominance of specific factors will influence the impact of 

segmentation. 

The data used in the analysis are subject to error due to the unique nature of drilling contracts 

(Moomjian, 2012 and 1999). Contracts differ in important ways outside of dayrates which may 

make direct comparisons less meaningful. Depending on contract terms, dayrates may be 

adjusted periodically, and these adjustments may or may not be specified in the dataset. In some 

cases, the costs of mobilization may be paid in a lump-sum while in other cases dayrates may be 

prorated to account for these costs; these terms are not specified in the data. 

5.12. CONCLUSIONS AND IMPLICATIONS

Dayrates are the leading indicator of the offshore contract drilling market and are tracked and 

widely reported by a number of commercial service providers. A body of common knowledge 

has developed over the years, but has not been subject to empirical verification. The analyses 

provided in this chapter generally confirm widely-held industry assumptions. 

Demand for drilling services is positively associated with oil prices for both jackups and 

floaters. The best predictors of demand were long-term moving averages suggesting that shortterm price fluctuations associated with seasonal or temporary geopolitical events do not 

significantly impact activity in the market. 

Dayrates increase with increasing oil prices for both jackups and floaters. Long-term moving 

averages of oil prices were the best predictors of dayrates, consistent with the hypothesis that 

high oil prices increases global demand and leads to increasing dayrates. Effects were consistent 

across regions indicating that regions respond similarly to increases in prices. 

Dayrates and utilization rates are positively correlated, but the strength of the relationship 

varies over time and across regions. While utilization is a significant predictor of dayrates, a 

large portion of the variation in dayrates is not explained by utilization rates, suggesting that 

other factors such as regional prospectivity are also important. 

Rigs capable of drilling deeper wells, working in greater water depths, or with more 

advanced station keeping capabilities have higher dayrates than rigs with lower specifications, 

and these results were typically consistent across regions, but the value of the premium varied 

and the premium was consistently lower in the West African floater market than in other regions. 

Long-term contracts exhibit higher dayrates than short-term contracts and the relationship is 

robust throughout the decade suggesting that E&P firms have been willing to pay more to secure 

drilling capacity. 
64

After controlling for regional and temporal variation, NOCs pay higher dayrates than IOCs or 

independents in the jackup market, and pay higher dayrates than independents, but not IOCs, in 

the floater market. NOCs may thus overinvest in drilling relative to private firms. 

Transocean and other large contractors receive higher dayrates than their competitors, but the 

difference is not significant after controlling for rig specifications. There is no evidence that 

large firms are able to use their market power to increase dayrates, consistent with the view that 

the industry is highly competitive. 

Appraisal drilling receives higher dayrates than exploratory or developmental drilling in the 

floater market, but not in the jackup market. The higher dayrates for appraisal drilling in the 

floater market may be due to increased risk associated with appraisal drilling. 
65

6. CONCEPTUAL MODELS OF FIRM DECISION-MAKING 

Companies that own drilling rigs conduct transactions and decide on newbuild programs and 

the best time to stack a rig. In this chapter, we develop models of acquisition and stacking to 

illustrate the primary factors in strategic decision making. Newbuilding and acquiring an existing 

rig are based on similar decision making processes, and here we focus on newbuilding. The 

models employed by industry are confidential but the economics of decision-making and future 

uncertainties governing the market are universal, so we suspect these models will broadly reflect 

industry results based on similar parameterizations. We begin by developing a net-present value 

model of the newbuilding decision and develop and parameterize a stacking decision model. We 

conclude with a review of net asset value estimation as a special case of the net present value 

model. 

6.1. NEWBUILDING 

Drilling contractors invest in newbuilding when the expected net present value (NPV) of 

adding a rig to the fleet is positive and justifies the risk (Cole, 1995). To achieve competitive 

returns, drilling contractors have to maintain a lean cost structure and control both its cash 

operating and capital costs, while optimizing the capital invested. Rig construction is highly 

capital intensive. In 2012, newbuild jackups cost on average $217 million, while newbuild semis 

cost $595 million and drillships $634 million, so strong returns are critical to attracting the lowcost debt and equity capital to finance newbuilding and acquisitions. 

Diversity in fleet composition and the maintenance of high quality, new rigs are important to 

the success of a firm because they enable operators to mitigate exposure to industry downturns 

(Speer et al., 2009). High quality drilling rigs generally continue operating during downturns 

whereas older lower quality units might be taken out of service. 

The decision to invest carries substantial risk because capital costs are significant and future 

market conditions are unknown. Factors that are known prior to undertaking a newbuild project 

are the capital cost of the vessel, finance terms, and the dayrate and duration of an initial 

contract, if applicable. Operating expenses can be estimated with a reasonable degree of certainty 

based on the company’s historical performance, and depreciation schedules are based on current 

regulations. The primary unknown variables are the dayrate and utilization rate after the initial 

contract period and are referred to as the outyear dayrate and outyear utilization rate. 

6.1.1. Model 

To illustrate the economics of newbuilding investment, a NPV model was developed for a 

hypothetical jackup rig with an economic life of 25 years. The rig is built speculatively, and no 

initial contract period is assumed; therefore, the outyear utilization rate is equal to the utilization 

rate. This assumption is relaxed later in the section. Table F.1 summarizes the variables used. 
66

Net Present Value 

The NPV represents the discounted sum of cash flows over a 25 year period: 

,

)1(

25

0





 



t

t

t

t

D

flowcashNet

NPV

where t is the year and D is the company discount rate. Cash flows in each year consist of 

income generated by leasing the rig minus capital and operating costs and taxes: 

Net cash flowt = Incomet – CAPEXt – OPEXt – Taxest.

The rig is assumed to have no residual value at the end of its 25 year life. 

Capital Costs 

Capital costs consist of the purchase price C of the rig and an upgrade in year 10, assumed to 

be 25% of the purchase price: CAPEX10 = C * 0.25. The initial capital expenditure is financed 

through the issuance of bonds with an interest rate, I, and a date to maturity T. Therefore, when t 

< T, debt repayment is: 

CAPEX *C I, t

and at t = T:

CAPEXt  I*CC .

Reactivation and Finance Cost 

In addition, a fixed $5 million capital expenditure is required in any year a rig is reactivated 

from a cold-stacked condition. To account for finance costs during construction, interest costs 

are accrued in year zero and income begins to be generated in year one. 

Operating Expense 

Operating costs include labor, maintenance, insurance, administration, and all other costs 

parameterized on a daily basis. Separate operating costs are accrued when the rig is active (Oa) 

and cold stacked (Os), and the rig may be in only one state in any given year (i.e. the rig cannot 

transition between active and cold-stacked states more than once per year). It is clear that Oa > 

Os. Annual operating costs are thus given by either: 

OPEXt = Oa * 365 or OPEXt = Os * 365, 

when the rig is active or stacked, respectively. 

Income 

Income is a function of the dayrate (DRt) times the utilization rate (Ut) in year t: 

Incomet = DRt * Ut * 365. 
67

Taxes 

Net income is taxed at rate X and discounted for depreciation of the rig. A straight line 

depreciation is assumed: 

.*

25

X

C

TaxestIncomet OPEXt 











 

6.1.2. Outyear Utilization Rate 

The offshore drilling market is cyclical, and during periods of low utilization, rigs are stacked 

to reduce operating costs. We develop two models of stacking referred to as “fixed utilization” 

and “variable utilization”.

Fixed Utilization 

In the fixed utilization model, the utilization rate is equal to a fixed average rate Ue

throughout the life of the rig, and stacking does not occur: 

Ut = Ue. 

Variable Utilization 

In the variable utilization model, the utilization rate is determined by a sine function varying 

around the mean: 

Ut = Ue + 0.5(sin t), 

where Ut is constrained between zero and one. In the variable utilization model, the rig is cold 

stacked in any year in which the utilization rate falls below 30%. When stacked, utilization is set 

to zero and operating costs are reduced (Figure F.1). 

Illustration

Figure F.2 illustrates the variable utilization rate given an expected utilization rate of 70%. 

The period of the utilization function is approximately six years, and over the course of its 25 

year life a rig cycles through four periods of high utilization and four periods of low utilization. 

Initially, the rig enters a period of high utilization, consistent with market conditions during a 

newbuild cycle, and after the fourth year utilization falls below 30% and is stacked. During the 

sixth year, the rig is active again and the cycle repeats. The rig is stacked when utilization falls 

below the line labeled “stacked.” When a rig is reactivated, we assume a fixed payment of $5 

million is required to bring a cold-stacked unit into an active state. 
68

6.1.3. Parameterization 

The model was parameterized under an expected and optimistic scenario. Under the expected 

scenario, capital cost is $200 million; active and stacked operating cost is 60,000 and 10,000 

$/day, respectively; bond interest rate is 4.5%, bond maturity is 7 years, and the tax and discount 

rates are 15%. Under the optimistic scenario, capital cost is $175 million; active and stacked 

operating cost is 50,000 and 6,000 $/day, respectively; bond interest rate is 3%, bond maturity is 

15 years, and the tax and discount rates are 10%. Additional assumptions are shown in Table F.2. 

The dayrate and average utilization rate were allowed to vary to explore the effect of changing 

assumptions on the break-even dayrate. Parameters were chosen based on financial information 

contained in the annual reports of large firms. 

The purchase price of rigs are widely reported and well known. Daily operating expenditures 

are not available for all contractors and regions, but Table F.3 shows values for jackups reported 

by select firms. In the 2010-2011 time period, operating costs for stacked jackups for the two 

companies varied between $6,700 and $12,000 per day, while operating expenses for active 

jackups varied from $32,000 to $58,000 per day for standard units, and $55,000 to $87,000 per 

day for high-spec jackups. Table F.3 also shows stacked and active operating costs of floaters for 

comparison. Stacked cost for floaters is comparable to jackup units, while operating cost is

significantly higher and ranges from $104,000 (midwater) to $150,000 (ultradeepwater). 

6.1.4. Model Results 

Break-even Dayrates and Utilization 

Figure F.3 shows the break-even combination of dayrates and utilization rates in the fixed 

utilization rate model under the expected and optimistic scenario. As the utilization rate 

increases, the dayrate required to break-even on the investment decreases since higher utilization 

rates translate into greater cash flows. 

Combinations of utilization and dayrates above the lines indicate a positive NPV, while 

combinations below the lines indicate a negative NPV. The break-even relationship is nonlinear 

and the difference between the expected and optimistic scenarios decreases as utilization rates 

increase. However, even at high utilization rates the difference between the scenarios is 

significant. At 90% utilization, the difference in dayrates between the optimistic and expected 

scenarios is $44,000. The model suggests that high utilization and dayrates are required to justify 

investment and at utilization rates of 90%, dayrates of at least $150,000 are required to make the 

NPV positive. 

Impact of Fixed and Variable Utilization 

The results of the expected scenario using the fixed and variable utilization rate models are 

shown in Figure F.4. At low utilization rates, the difference between the fixed and variable 

models is significant, and the fixed rate model requires much higher dayrates to justify 

investment. As the average utilization rate increases, the difference between the models 

decreases, and at average utilization rates Ue above 70%, the fixed utilization model gives 

slightly more favorable results than the variable utilization model. The crossover observed in 

Figure F.4 occurs because the maximum utilization rate is limited to 100% in the variable 
69

utilization model, and at high utilization rates, the sine function cannot further increase 

utilization and will result in lower average utilization rates. The optimistic parameterization 

yields similar results to the expected scenario, but break-even dayrates are approximately 

$50,000 to $100,000 $/day lower. 

Drilling contractors are unlikely to consider building if they believe that future utilization 

rates will be low, and so the left extreme of Figure F.4 is of less relevance to the investment 

decision. At average utilization rates above 60%, the fixed and variable utilization models yield 

similar results, and the fixed rate mode is a good approximation to the variable rate model. 

Effects of an Initial Contract 

To examine the effects of an initial contract on NPV, we added an initial contract with a two 

year period to the model. During the two year period, the rig had a utilization rate of 100%, 

followed by a fixed utilization rate for the remainder of the rig’s lifecycle. Figure F.5 compares 

the results of the expected parameterization with an initial contract to the expected 

parameterization with fixed and variable utilization rates without an initial contract. At low 

utilization rates, an initial contract reduces the break-even dayrates relative to the variable 

utilization model, but the differences were mostly minor. At higher utilization rates, the breakeven dayrates of all three models converge. The presence of an initial contract reduces risks, but 

the difference is small. At 70% utilization, the difference in break-even dayrates is about 

$15,000/day. 

6.1.5. Sensitivity 

The percent change in the break-even dayrate given a 1% change in selected parameters is 

shown in Table F.4 for both the fixed and variable utilization models. 

In the fixed utilization rate model, the rate of change in break-even dayrates is constant 

across utilization rates, and a single rate of change is shown under the expected scenario. In the 

variable utilization model, the sensitivity is dependent on the initial utilization rate. For example, 

in the variable utilization model, a 1% increase in active operating costs increases break-even 

dayrates by 0.26% when utilization rates are low (Ue = 5%), but increases break-even dayrates 

by 0.5% when utilization rates are high (Ue = 100%). The sensitivity of the model is shown at 

very high and very low utilization rates. Intermediate utilization rates have intermediate 

sensitivities. 

For both the fixed and variable utilization models, changes in the purchase price and 

operating costs have a significant impact on break-even dayrates, but the impact of the interest 

and tax rates are minimal. For all parameters, a 1% change in the selected parameter results in a 

change in break-even dayrates of less than 1%. The relatively low sensitivity of the model to 

changes in operating costs is not intuitive. We might expect that a 1% increase in operating costs 

would require at least a 1% increase in dayrates, but operating costs are a fraction of dayrates, 

and while a $1 increase in operating costs does incur a $1 increase in dayrates, a 1% increase in 

operating costs causes a more modest increase in break-even dayrates. 
70

Figure F.6 shows the change in break-even dayrates under variable discount rates. For the 

fixed utilization model we apply expected assumptions and a 70% utilization rate. The breakeven dayrate increases as the discount rate increases, but at discount rates above 15%, the breakeven dayrate flattens out and starts to decline. The negative relationship at high dayrates is 

atypical of NPV models, but occurs because of the finance structure. In the model, the vessel is 

purchased through the sale of bonds with a maturity date several years into the future. As the 

discount rate increases, the value of the principal payoff declines, making the NPV more 

positive. 

6.1.6. Limitations 

The model is a simplification of the newbuilding decision. Factors that were not considered 

include a variable dayrate, the effects of adding a rig to the fleet on the dayrates of the other rigs 

in the fleet, and the remaining value of the rig after the 25 year model duration. The impact of 

excluding these factors is briefly described. 

A mean dayrate was employed in the model, but in reality, dayrates will vary around a mean, 

and the temporal distribution of the variance is important. Future cash flows are discounted, so if 

dayrates fall below the average early in the rig’s lifetime but later exceed the mean, the NPV of 

the investment will decline. If the near term future is more predictable than the distant future, and 

if realized dayrates accurately reflect the mean during the first 5 to 10 years of service, the results 

of the model are likely to be similar to the actual NPV. 

The decision to newbuild typically results in the net addition of a rig to the fleet, increasing 

supply, and potentially decreasing dayrates for the other rigs in an operator’s fleet. This should 

make drilling contractors more conservative when evaluating newbuilding decisions. The effects 

of a small increase in fleet size on dayrates and utilization rates are difficult to detect, but the 

cumulative impact of several drilling contractors making investment decisions simultaneously is 

more significant. 

Rigs are designed to have operational lives of around 25 years, but rigs often work for 30 

years or more and the oldest operating rig in the current fleet is 54 years old. Therefore, 

significant value remains in the rig beyond the 25 year design life suggested in the model. Since 

it is difficult to predict market conditions 25 years in the future, it is difficult to estimate this 

value in a reliable way. 

The financing structure of the model may be inappropriate for smaller firms and firms with 

high debt loads. We assumed that firms would raise capital through the issuance of bonds which 

is a major source of capital for large firms. In many cases, firms use more traditional loans to 

finance construction. Loans have higher interest rates and require repayment of capital earlier 

than bonds, and both of these factors would increase the dayrates and utilization required to 

justify construction. Many bank loans used in the industry utilize balloon payments at the end of 

the term and would have a financing structure similar to bonds. 
71

6.2. STACKING

6.2.1. Decision Model 

Stacking Criteria 

Firms cold-stack rigs when the expected income received from the asset is less than the rig 

operating costs, or when the costs of stacking are less than the net costs of operating: 

Costs of stacking < Net costs of operating. 

The costs of stacking include the costs to prepare the rig for storage (deactivation costs), the 

operating costs during storage (OPEXs) and the costs to reactivate the rig (reactivation costs): 

Costs of stacking = Deactivation costs + Reactivation costs + OPEXs.

The net costs of operating consist of the income received minus the active operating costs 

(OPEXa). 

Net costs of operating = Expected income – OPEXa. 

Thus, a rig should be stacked if: 

Deactivation costs + Reactivation costs + OPEXs < Expected income – OPEXa. 

Deactivation Costs 

Deactivation costs are a fixed cost and all other costs are a function of time. Reactivation 

costs are assumed to include a fixed and variable component: 

Reactivation costs = F + R * y, 

where F is a fixed cost associated with rehiring and training workers, R is the reactivation costs 

needed to bring back a cold-stacked unit to an active state, and y is the number of days the rig is 

idle. 

Operating Costs 

The operating costs while cold-stacked are given by the daily operating cost times the 

number of days the rig is idle: 

OPEXs = Os * y,

OPEXa = Oa * y,

where Os and Oa are the daily operating costs in the stacked and active states, respectively, and y 

is the number of days the rig is idle. 
72

Lost Income 

The potential lost income is the expected dayrate multiplied by the expected utilization rate 

and the number of days the rig is idle: 

Expected income = DR * Ue * y, 

where DR is the dayrate and Ue the utilization rate. Table F.5 summarizes the model variables. 

Sign Convention 

Since the stacking decision model is an inequality, the sign of the variables is important. We 

assume that all of the variables defined above are positive, for example, deactivation costs are 

$1,000,000 rather than -$1,000,000. As a result, the costs of stacking, as defined, will always be 

positive, but the net costs of operating may be positive or negative. Therefore, we force the costs 

of stacking to be negative, and change the direction of the inequality: 

– (Deactivation costs + Reactivation costs + OPEXs) > Expected income – OPEXa. 

Therefore, a rig will be stacked if the costs of stacking are less negative (greater) than the 

costs of operating. If the expected income minus the OPEXa is positive, the rig will not be 

stacked. For example, if: Deactivation costs + Reactivation costs + OPEXs = $1,000,000, 

Expected income = $1,000,000, and OPEXa = $3,000,000, then the inequality becomes: 

– [1,000,000] > 1,000,000 – 3,000,000,

and the rig should be stacked. If the expected income increased to $3,000,000, the rig would not 

be stacked because: 

– [1,000,000] < 3,000,000 – 3,000,000.

6.2.2. Parameterization 

We parameterize the model for a low-spec jackup. Low-spec jackups are the most common 

cold-stacked rigs and reliable cost information is available from several contractors. Here we 

apply the quarterly reports of Hercules Offshore from 2010-2011. The costs to deactivate and 

operate the rig in a cold and ready-stacked condition are well known, but the time the rig will be 

out of service, and the potential lost income can only be estimated. We fix the deactivation costs, 

the fixed component of reactivation costs (F), and the operating costs (Oa and Os), and allow the 

dayrate and utilization rate to vary. 

The costs to deactivate a rig include costs to move the rig to a storage location and secure the 

rig for storage. A reduction in the workforce will be associated with reduced direct and indirect 

costs, but short-term administrative cost may be incurred. Deactivation costs are not typically 

reported in financial documents, and we assume a fixed cost of $1,000,000. Reactivation costs 

for jackups typically range from $5 to $10 million depending on the condition of the rig. We 

assume a fixed cost of reactivation of $3 million and variable costs of $4,000 per day. Operating 
73

expenses for an active rig depend on the size, age and replacement value. For an older jackup 

operating expenses are assumed to be $35,000 per day. For a cold stacked jackup, operating 

expenses are assumed to be $8,000 per day. 

6.2.3. Model Results 

The relationship between utilization rate and the benefit of stacking a rig for one year under 

the assumptions described and at dayrates above and below the operating expense of the rig is

shown in Figure F.7. Negative values indicate that stacking the rig is the preferred strategy and 

positive values indicate that the rig should be operated. When the expected dayrate is $30,000 

($5,000 below operating costs), the contractor must expect a utilization rate of approximately 

45% to justify operating the rig. When the expected dayrate is $40,000 ($5,000 above daily 

operating expenses), the contractor requires a utilization of at least 35% to justify operation. 

Thus, depending on the utilization rate, cold-stacking can be preferred even if the dayrate is 

greater than operating costs; conversely, operating the rig may be preferred even if the dayrate is 

less than the daily operating costs. 

The effect of the duration of cold stacking on the stacking decision is shown by Figure F.8. 

Utilization is held constant at 50% for both dayrates. At dayrates of $40,000 per day, the rig 

makes money and stacking is never the preferred option. However, at dayrates of $30,000 per 

day, operating costs are higher than revenues and the owner loses money operating the rig for 

longer than 500 days. If the rig is to be stacked for 500 days or less, operating the rig is still the 

preferred strategy because of the high fixed costs associated with stacking. 

6.2.4. Limitations 

Stacking decisions are complex because firms typically operate several rigs in the same 

region, and the preferred strategy is the one that maximizes revenue for a firm’s fleet, which in 

part depends on the market position of the firm and its ability to capture the largest portion of 

available contracts at rates above operating expense. Large market shares typically indicate 

technological leadership and commands premium pricing. 

By stacking rigs, a firm may be able to improve utilization rates and keep dayrates higher for 

the rest of its fleet. Corts (2008) studied the stacking decisions of large and small firms for two 

years from 1998 to 2000 and found that large firms stack and reactivate rigs more rapidly than 

smaller firms. He attributed this to lower reactivation costs for large firms due to their greater 

ability to retain labor. As the costs of reactivation decline, firms are expected to stack and 

reactivate their rigs more rapidly in response to changing market conditions and business 

strategy. 
74

6.3. NET ASSET VALUE

6.3.1. Definition 

The net asset value (NAV) of a rig is the discounted value of the rig’s expected future net 

earnings. Several market research firms estimate the NAV of a drilling contractor’s fleet for 

investment purposes. Jefferies, Standard and Poor’s and ODS-Petrodata each develop NAV 

estimates and their data is widely referenced in the industry (Slorer et al., 2011; Glickman, 

2006). Jefferies and Standard and Poor’s calculate NAV for a particular rig, while ODSPetrodata calculates NAV for a rig class (e.g. second generation semisubmersibles). 

NAV is the summation of future expected cash flows and is estimated by calculating 

operating income for a rig based on current and future projected dayrates, estimated operating 

expenses, and estimated rig utilizations. Income is projected over a defined period (in the case of 

Standard and Poor’s it is 10 years) and a residual value is added which is an estimate of the value 

of the rig after the duration of the income projection. 

ODS-Petrodata valuations by rig class in the 4Q 2011 are shown in Table F.6 and Figure F.9 

shows Jefferies NAV calculations for selected rigs. NAVs are a function of time and depend 

upon the rig’s current and expected future contracts and related factors. As contracts expire and 

market conditions change, new contracts are negotiated which impact NAV calculations. 

In Figure F.10, Jefferies’ NAV estimates for the Galaxy II and Galaxy III jackups from 2009 

to 2012 illustrate the time dependent nature of NAV assessment. The durability of NAV depends 

upon the length of a contract, and when contracts expire, NAV estimates change. In a down 

market with declining dayrates, NAV will generally decline, and conversely, when dayrates are 

increasing, NAV will increase. The rig valuations for Galaxy II and Galaxy III follow the same 

pattern but are not identical and depend on the specific contract each rig is working under at the 

time of valuation and the assumptions of the analyst. 

6.3.2. Model 

Conceptually, NAV models are similar to the NPV model described previously, where the 

NAV is the purchase price C that makes the NPV zero; that is, it is the fair market value of a rig. 

By modifying the NPV model, we estimate NAV. 

The NAV model is a simplified version of the NPV model described in Section 6.1.1. NPV is 

given by: 

.

)1(

25

0





 



At

t

t

t

D

flowcashNet

NPV

The model is iterated over the remaining lifetime of the rig, assuming an initial age, A, and a 

total lifetime of 25 years. Net cash flow is composed of income, operating expenses, and taxes, 

as before: 
75

Net cash flowt = Incomet – CAPEXt – OPEXt – Taxest.

Income, operating expense, and taxes are estimated as in the NPV model. A constant 

utilization rate is assumed (Ue = Ut). No finance structure for the capital expenditure is assumed 

so that the NAV is equal to the purchase price that makes the NPV equal to zero: CAPEX1 = C, 

and when NPV = 0, NAV = C. We parameterize the model for jackups by modifying the 

expected parameterization used previously (Table F.7). 

6.3.3. Model Results 

The net asset value of rigs of different ages and under different assumptions of future dayrate 

and utilization rate is shown in Figure F.11. In the top panel, utilization is held constant at 90% 

and dayrates vary. In the bottom panel, dayrate is held constant at $120,000 and utilization rates 

vary. At low dayrates and utilization, the difference in NAVs for old versus newer rigs is minor, 

but as the dayrate or utilization rate increases, the NAV difference also increases. In reality, the 

age of the rig is expected to interact with dayrates and utilization, and old rigs are expected to 

have lower dayrates and utilization while newer rigs are expected to be more active and to 

capture higher dayrates. 

6.3.4. NAV Comparison 

In Table F.8, our NAV estimate is compared with Jefferies NAV estimates for two 

Transocean rigs. The default model parameters were used in the estimation, and the dayrates 

reflect January 2012 values for each rig. The NAV estimates match relatively closely; however, 

our estimates are slightly lower than Jefferies reflecting different assumptions on future dayrates, 

discount rates and the lifespan of the rigs. 

6.3.5. Alternative Formulations 

Industry models will differ from our development, but in most respects, the results are 

expected to be broadly similar under similar parameterizations. We assumed a total rig lifetime 

rather than attempting to estimate a residual rig value at some future point which both simplifies 

the calculations and leads to a conservative estimation. The model could be parameterized with 

contract data for a specific rig (as performed by Jefferies and Standard and Poor’s), or with 

average dayrates and utilization for a rig class (as performed by ODS-Petrodata). In either case, 

older rigs would be parameterized with lower dayrates, utilization and operating costs than newer 

rigs. 
77

7. JACKUP CONSTRUCTION MARKETS 

Rig construction combines steel forms and machinery using capital and labor. Worldwide, 

the offshore oil and gas industry is a major consumer of shipbuilding services, and rig 

construction is a major fraction of shipbuilding in support of oil and gas activities. In the 

Southeastern U.S., shipbuilding in support of the offshore oil and gas industry is culturally and 

economically important, and while rig construction has declined in the past decades, it remains 

locally important in a small number of communities. The purpose of this chapter is to introduce 

the jackup construction market with an emphasis on the U.S. We describe the demand factors, 

players, and contract structures that impact jackup construction markets. 

7.1. HISTORICAL OVERVIEW

The number of jackup rigs delivered by region over the past six decades is shown in Figure 

G.1. From 1950 to 2012, a total of 641 jackup rigs have been constructed. The U.S. constructed 

37% of the total number of jackup rigs during this period, with Asia contributing 45%, and 

Western Europe 8%. Since 2000, Asia has constructed 70% of the rigs delivered, followed by 

14% in the U.S. and 16% in all other countries. 

Jackup construction began in the U.S. in the mid to late 1950’s and was dominated by U.S. 

shipyards in the 1960’s. Major players in the period included Marathon LeTourneau, Bethlehem 

Steel and Levingston. In the early to mid-1970’s U.S. firms invested in Singaporean shipyards to 

reduce transport costs for offshore exploration in the region (Khiam, 2007; ASMI, 2011; Leong, 

2006). Simultaneously, Western European, Canadian and Japanese firms developed the 

capability to compete and the construction market grew significantly. 

The 1970’s and early 1980’s saw significant increases in the price of oil and improvements in 

jackup technology which lead to strong demand growth. The growth in demand encouraged new 

market participants, and by the mid 1980’s, shipyards in 23 countries had delivered rigs 

including France, Singapore, Russia, Brazil, and Romania. At its height in the late 1970s and 

early 1980’s, 11 U.S. shipyards were engaged in rig construction, including six in Texas, three in 

Mississippi and one each in Maryland and South Carolina (Colton, 2011). 

Oil prices began to fall in the early 1980’s, and by 1985, new jackup orders had declined 

precipitously. Between 1980 and 1985, 244 jackups were delivered, but between 1986 and 2000, 

only 30 rigs were delivered. In early 2000, the aging jackup fleet began to encourage new orders, 

most of which were placed in Singaporean yards (Figure G.2) due to the movement of shallow 

water exploration activity in other parts of the world and the general decline in the 

competitiveness of U.S. shipbuilding (Koenig et al., 2003). The pace of deliveries accelerated in 

2006 due to increases in the price of oil, receded in late 2008 following the economic recession, 

and began again in late 2010. 
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7.2. DEMAND FACTORS

The demand for drilling rigs is impacted by oil prices, utilization and dayrates, technology, 

the number of countries open to exploration, field discoveries, fleet age, and construction cost. 

Jackups have water depth limitations and can only operate in 500 ft of water. 

7.2.1. Oil Prices 

The number of jackups and floaters delivered worldwide from 1974 to 2012 is depicted in 

Figure G.3 and correlated with the two-year lagged average annual oil prices in Figure G.4. The 

lag is roughly equal to the time to build a jackup and suggests that drilling contractors respond 

rapidly to changing oil prices by ordering rigs. Deliveries in floating rig construction follow a 

trend similar to the jackup market but the statistical relationship is not significant. 

7.2.2. Utilization and Dayrates 

When utilization rates are high, there is little spare capacity in the contract drilling market, 

leading to increases in dayrates. This signals to drilling contractors that additional capacity may 

be absorbed by the market and increases the dayrate and utilization rate assumptions used in the 

financial analysis of a newbuilding decision. Figure G.5 shows the relationship between the 

number of rigs delivered and the lagged global average jackup dayrates between 2000 and 2012. 

Dayrates explain over 80% of the variation in deliveries, suggesting that dayrates are an 

important signal to investors. New companies are encouraged to enter the market by high 

dayrates and utilization rates which add to demand during market upswings. 

7.2.3. Technology 

Improved technology and an interest among E&P firms in developing more technically 

challenging resources can also stimulate newbuilding demand. In the floating rig market there 

was a brief period of high activity from 1998 to 2002 which was driven not by oil price 

increases, as oil prices remained low during this time, but by the maturation of deepwater drilling 

technology which allowed drilling in water depth beyond 5,000 ft (Cantwell, 2000). Likewise, 

interest in HPHT shallow water drilling led Rowan to order several high-specification jackups in 

the early 2000’s (Maksoud, 2002).

7.2.4. New Discoveries 

In some cases, E&P firms order rigs to fulfill a specific exploratory or developmental role. 

For example, in 2009, Petrobras announced plans to build up to 28 drillships for the Brazilian 

market as part of a major investment in its pre-salt fields. While oil prices and technological 

development are also important factors in the Petrobras order, the order is a direct result of 

Petrobras’ 2006 pre-salt discoveries. As more countries open their offshore waters to exploration, 

demand for rigs will increase. 

7.2.5. Fleet Age 

Rigs are exposed to a corrosive environment and over time steel in the hull and legs corrodes 

and must be replaced. Eventually, the maintenance and refurbishment costs exceed the returns 

generated by operation, and the rig is sold for scrap, placed in long-term storage or converted to 

another use. Rigs are designed for a 25 year operational life, but many rigs built in the 1977-
79

1985 period remain operational in 2012. Fleet age provides a signal to investors that new rigs 

may be required in the future (Wiseman, 2003).

7.2.6. Construction Cost 

The newbuild market is historically cyclical. During periods of low demand, construction 

costs decline which may stimulate demand from drilling contractors. By building during market 

downturns, drilling contractors increase the risk that the newbuilt rig will not be immediately 

utilized, but pay lower capital costs and lower the overall financial risk associated with 

newbuilding. Historically, construction cost has not been a major driver of demand, and few 

firms take advantage of low prices to order rigs. 

7.3. PLAYERS

Countries building rigs in 2012 are shown in Table G.1. Singapore is dominant in jackup 

construction, Korea is dominant in drillship construction, and semisubmersible construction is 

split between China, Korea and Singapore. Shipyards in the UAE and India also build jackups. 

Table G.2 shows the distribution of rig construction by shipyard for deliveries between 2005 

and 2012. Keppel and Sembcorp are dominant in jackup and semi construction, while Samsung 

is dominant in drillship construction. The market capitalization of selected shipyards on Dec 31, 

2011 is also depicted. Many industry players are either not publicly traded or are subsidiaries of 

larger firms. The market cap of these firms is not included to facilitate comparison. Keppel is the 

largest player in the industry by a significant margin, and Sembcorp is the only competitor in the 

jackup market that is of approximately the same scale. 

7.3.1. Singapore 

Singapore is the largest producer of jackup rigs and is also dominant in semisubmersible 

construction. Keppel and Sembcorp are the major players, with Keppel being the larger of the 

two. Together, these two firms have the capacity to deliver approximately 25 jackups annually, 

and between 2008 and 2011 averaged 12 jackups and three semi deliveries per year. In 2011, 

Keppel had a market capitalization of $15.1 billion compared to $8.8 billion for Sembcorp, and 

their combined revenues accounted for approximately 2% of Singapore’s GDP. The offshore 

industry accounts for 9% of total Singaporean manufacturing output. 

A primary advantage of Singaporean shipyards is their low labor costs due to the use of 

foreign workers. Sembcorp and Keppel employed over 20,000 people in Singapore in 2011, and 

over 75% of these employees are foreign workers which allows Singaporean shipyards to pay 

employees less than one-third as much as their Korean competitors (Wong and Chang, 2011). 

Both Keppel and Sembcorp utilize shipyards throughout in Asia to minimize production cost 

and achieve scale economics. Singaporean yards are physically constrained due to the lack of 

land, and face increasing labor costs associated with taxes levied on the employment of foreign 

workers. As a result, Sembcorp and Keppel outsource work to company-owned yards in 

Indonesia and China to assemble hulls or other modular components with final assembly 

occurring in Singapore. 
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Keppel 

Between 2005 and 2012, Keppel delivered 38 jackups, 10 semis and two drillships from its 

Singaporean yards. Keppel owns rig building and repair shipyards in eleven countries, but most 

of their newbuilding is performed at the Keppel FELS shipyard in Singapore. Figure G.6 shows 

the layout of one of the four facilities at Keppel FELS. The Pioneer yard is designed to 

accommodate three jackups and one semisubmersible in drydocks, as well as several jackups, 

semis and drillships in quays. In the plan schematic, two drillships, four semis and one jackup 

are shown quayside. In the satellite view, three jackups, five semis and one liftboat are present. 

Keppel also owns yards in the U.S., Brazil, Norway, Azerbaijan, Kazakhstan, UAE, Qatar, 

China, the Philippines and Indonesia. With the exception of Keppel AmFELS in the U.S., 

Keppel’s international yards are primarily focused on repair and/or non-rig construction. 

Keppel’s shipyards build a variety of rig designs, but the majority of their rigs use proprietary 

designs. Unlike other design firms, Keppel does not typically license its designs to other 

shipyards and their most important product is the KFELS B Class. The use of proprietary designs 

increases efficiency through learning as shipyards can improve manufacturing processes and 

optimize purchasing and logistics. These factors, along with the elimination of the license fee, 

are estimated to reduce costs by 10 to 15% (Wee, 2008). 

Sembcorp 

Sembcorp is the second largest firm in the jackup construction industry and between 2005 

and 2012 delivered 33 jackups and 10 semisubmersibles. Sembcorp owns two major rig building 

shipyards: PPL and Jurong (Figure G.7). PPL owns the Pacific Class 375/400 design, and these 

rigs have made up most of the deliveries from the PPL yard. The Jurong yard has specialized in 

the F&G JU 2000/3000 class rigs but is also active in semi construction. In addition to its 

activities in rig construction, Sembcorp owns repair facilities in Sabine, Texas and Brazil, and 

operates yards in Singapore specializing in medium and large cargo vessels. 

7.3.2. China 

Rig construction in China has grown rapidly in recent years. In 2006, the first Chinese built 

jackup rig was delivered, and by 2011, China was the third largest construction market with 

significant market share in both the jackup and semi segments. In 2011, six shipyards were 

building jackups in China with Dalian and Yantai Raffles being the largest players. CIMC 

Raffles and COSCO are the largest Chinese players in the semi market and are currently building 

10 semis. Three drillships are also under construction in China. All of the major players in the 

Chinese market are state-owned but build rigs for both state-owned and international contractors. 

7.3.3. South Korea 

South Korean shipyards do not build jackups but are the dominant firms in drillship 

construction. South Korean players include Hyundai, Samsung and Daewoo. These three firms 

delivered 86% of drillships and 20% of semisubmersibles from 2005-2012. In January 2012, 

they are constructing over three-quarters of drillship orders. Samsung and Daewoo primarily 

build their own proprietary designs while Hyundai builds mostly Gusto MSC designed drillships. 
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7.3.4. United States 

Jackup Deliveries 

In the Southeastern U.S., shipbuilding in support of the offshore oil and gas industry is 

culturally and economically important (Abel and Taylor, 2008). Table G.3 shows deliveries of 

jackup rigs from U.S. shipyards between 2000 and 2012. During this period, the LeTourneau 

yard in Vicksburg, Mississippi delivered 11 rigs, and the Keppel AmFELS yard in Brownsville, 

Texas delivered 14 rigs. In addition, one liftboat with an attached rig was delivered from a 

shipyard in New Iberia, Louisiana. On average, approximately two jackups have been delivered 

each year over the past decade. 

Table G.4 shows non-jackup MODUs delivered between 2000 and 2012. Five 

semisubmersibles were delivered from U.S. shipyards from 2000 to 2002, however, three of the 

five vessels had their hulls built in Asia and were only outfitted in U.S. yards. Requirements for 

outfitting rigs are significantly different from the requirements for hull construction and are 

generally less specialized and capital intensive. The Q4000 is not a drilling rig but a 

semisubmersible well intervention unit. While it is possible that an oil services firm could 

require a Jones Act certified vessel like the Q4000, barring a major change in market conditions, 

semisubmersible and drillship newbuilding is unlikely to occur in the U.S. in the foreseeable 

future. 

Vicksburg, Mississippi 

The LeTourneau yard in Vicksburg, Mississippi was the first shipyard to build a jackup rig in 

the U.S. and between 1958 and 2010 delivered 87 rigs (LeTourneau Technologies, 2010). The 

yard is located on 90 acres adjacent to the Mississippi River (Figure G.8) and exclusively builds 

LeTourneau designed rigs. In recent years, several Workhorse 240C class rigs have been built. 

Due to the height of the bridges along the Mississippi River, only the lower sections of legs 

are attached to the rig in Vicksburg with the upper sections fabricated in Vicksburg and attached 

at the company’s shipyard in Sabine Pass, Texas. The derrick must also be attached after leaving 

Vicksburg. The Vicksburg shipyard does not have the ability to modify or repair rigs due to the 

bridges, nor does it have the infrastructure typically associated with large shipyards (drydocks or 

launching systems) and must instead “walk” the rig into the water. Despite its historical success, 

the Vicksburg shipyard has attracted smaller numbers of new orders and has apparently become 

uncompetitive. 

From 2000-2011, LeTourneau was owned by drilling services contractor Rowan which was 

the shipyard’s major customer. In 2011, LeTourneau was sold to Joy Global which then sold 

LeTourneau’s drilling equipment operations to Cameron for $375 million (Elswick, 2011). After 

the delivery of the Joe Douglas in 2011, the shipyard has no further work contracted, but it is 

likely that some work will continue in Vicksburg, primarily the construction of legs and 

elevating systems for LeTourneau designed rigs built elsewhere. 
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Brownsville, Texas 

The Brownsville shipyard is located on approximately 170 acres along the Brownsville Ship 

Channel east of Brownsville, Texas (Figure G.9). The yard began building offshore drilling rigs 

in 1973 as the Marathon LeTourneau shipyard. In 1991 it was bought by Keppel and renamed 

Keppel AmFELS. 

Since reopening, AmFELS has primarily built jackup rigs, but has also built a tension leg 

platform, accommodation platforms, the Q4000 semisubmersible deepwater intervention vessel, 

drilling barges, derrick barges and other vessels. The AmFELS yard has also upgraded several 

jackup and semisubmersible rigs, including the jackups Ocean Spartan and Ensco 67,

semisubmersible Hakuryu-5, and converted a semisubmersible drilling platform to a floating 

radar system for the U.S. military. In 2012, AmFELS was contracted by Diamond Offshore to 

conduct a $150 million rebuild and upgrade of the semisubmersible hull, Ocean Voyager. Since 

2007, AmFELS has primarily built LeTourneau-designed Super 116E rigs for Rowan, 

Perforadora Central and Scorpion Offshore (now part of Seadrill). AmFELS has secured jackup 

construction work through early 2013 and stands to benefit from any reduction in activity at the 

Vicksburg yard. 

7.4. BUYERS

The number of newbuild rigs in the fleets of selected drilling contractors is shown in Table 

G.5. All rigs delivered after 2005 are included in the count as well as rigs under construction in

1Q 2012. Seadrill has been the major consumer of newbuilt rigs and has nearly twice as many 

newbuilt rigs as Transocean. COSL has also been a major consumer of newbuilt rigs, particularly 

relative to its smaller total fleet size. In the U.S., Scorpion and Rowan have been the major 

buyers and have purchased five and 14 rigs, respectively, since 2000. 

7.5. CONTRACTS

Contracts for rig construction are fixed-price turnkey contracts where the risk of cost 

escalation is held by the builder. Contracts are awarded in a competitive bidding process in 

which the buyer solicits bids from shipyards for the construction of a rig meeting certain 

specified criteria. The shipyard estimates the construction cost of the rig based on steel, labor and 

equipment prices, profit margins, and the rig design. Because the contract is fixed-price, accurate 

cost estimation is critical. 

Contracts normally include three major categories of clauses: clauses that specify the 

product, clauses that specify the price, and clauses that detail responses to unforeseen events and 

apportion risk (Atwood Oceanics and PPL Shipyard, 2010; Santa Fe International and PPL 

Shipyard, 2001). 

7.5.1. Product Specification 

Detailed construction specifications are attached to the contract and construction practices 

are defined by classification society rules. Typically, the buyer is allowed to place a full-time 

technical representative at the yard to ensure compliance with contract specifications. A delivery 
83

time and place is specified. Acceptance of the vessel is based on satisfactory performance in sea 

trials and classification society acceptance. 

7.5.2. Payment Schedule 

Payments are made in installments at the execution of the contract, delivery, and at one or 

more project milestones. The methods by which the builder demonstrates completion of a given 

project milestone are defined. A schedule of penalties and options are defined if either the buyer 

fails to make a payment on time or the builder fails to deliver the rig by the specified date. The 

methods for accommodating changes to the vessel plans are described, which typically 

compensate the builder on a cost basis and allow for extensions in the delivery date. 

7.5.3. Unforeseen Events and Risk 

Force majeure clauses are used to differentiate between permissible and impermissible 

delays. Rig construction shipyards are located adjacent to waterways, typically in coastal 

regions, and are subject to flooding and hurricane risk. Contracts stipulate that the builder must 

carry a performance bond and insurance equal to the contract price and the circumstances under 

which bonds may be invoked are defined. A method for the mediation of contract disputes is also 

described. 

Rig construction contracts are long-term agreements that specify delivery several years into 

the future. It is difficult for shipyards to accurately predict future price changes in supplies, and 

suppliers may be unwilling to provide firm quotes for products several years in advance 

(Conway and Will, 2006). This creates risk for shipyards which can be managed with material 

cost escalation clauses linked to inflation indices. 
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8. NONTECHNICAL PRIMER ON JACKUP DESIGN 

The first offshore rigs were elevating barges designed for shallow water. As drilling 

progressed into deeper and more difficult environments, rigs evolved based upon the experience 

of the builder, operational performance, and the demands of the market. Designing a rig involves 

a number of tradeoffs between technical and economic factors. In this nontechnical primer we 

discuss the design factors that impact jackup construction and the most popular designs 

employed by industry. We discuss the major design factors and highlight the decisions made at 

the conceptual and preliminary stages. We conclude with a brief discussion of popular U.S. and 

international jackup rigs. For additional and more detailed information, the reader is referred to

Gieger, 2004, Howe, 1986, Rammohan, 2005, and Vazquez et al., 2005. 

8.1. DESIGN PROCESS

Rig designers balance a number of technical and economic factors as they move through 

design phases similar to ship construction (Figure H.1). The process is iterative and includes 

conceptual, preliminary and contract (detailed) phases (Eyers, 2007). Preliminary (or basic) 

designs for jackup rigs consist of the leg structure, spudcan, hull, deck diagrams, and information 

on electrical systems, piping systems and other systems. Detailed design work is performed after 

a contract is written and plans are customized to the clients’ needs. 

8.2. NOTABLE FEATURES

There are approximately a dozen popular modern designs. Functionally, the designs differ in 

their water depth capability and storm environment, variable deck load, quarters, crane capacity, 

installed power, and storage dimensions. In Figure H.2, four common design classes are shown: 

the BMC Pacific 375, KFELS N Class, LeTourneau 240C and LeTourneau Super 116E. The 

KFELS N Class is a harsh environment rig while the other three rigs are designed for moderate 

environments. Several features are notable. 

(1) The hulls of the rigs are triangular and the legs are located at the corners of the 

hull for maximum stability. 

(2) All four rigs depicted, and virtually all newbuilds, use trussed legs. Most rigs 

use triangular legs, but some designs, such as the LeTourneau Super 116E, 

use square legs. 

(3) The hull is approximately twenty to thirty feet deep and there are typically 

several levels, including an inner-bottom, a machinery level, and a mezzanine 

deck (Figure H.3).

(4) The bottommost level of the hull is typically 3 to 6 feet deep. Above the innerbottom is the machinery deck, where four or more large diesel engines are 

installed, as well as pumps and other machinery. The main deck contains 

topside facilities and storage tanks for water, drilling fluids, fuel, and other 

liquids. 

(5) Topsides facilities include all the equipment for drilling, utilities, safety 

systems, accommodation, and life support. 

(6) All offshore rigs have a heliport for the transport of personnel, several cranes 

to perform heavy lifting operations, and common layouts. The heliport 
86

extends outside the hull for safety reasons and to avoid interference with 

drilling operations. 

(7) Harsh environment rigs are larger and heavier than moderate environment 

rigs. The KFELS N Class harsh environment design, for example, has a hull 

264 ft long by 289 ft wide. All the other rigs depicted are approximately 220 

to 240 ft wide and 200 to 240 ft long. 

8.3. JACKUP DESIGN FIRMS 

The principal firms designing jackup rigs are Friede and Goldman, LeTourneau, Gusto MSC, 

Baker Marine, and Keppel. The number of jackup rigs under construction worldwide by class in 

2012 and the number delivered over the past decade are summarized in Table H.1. The KFELS B 

class is the most commonly newbuilt rig, but the LeTourneau Super 116E and several Friede and 

Goldman designs are also popular. None of the designs included in the table are common in the 

legacy (pre 2000) fleet, but several designs have evolved from rigs built in the 1980 to 1985 

newbuild cycle, for example, the LeTourneau Super 116 is based on the earlier LeTourneau 116. 

8.4. DESIGN FACTORS

8.4.1. Number of Legs 

Early jackup rigs had a large number of legs, in some cases ten or more (Figure H.4). All 

modern jackup rigs under construction in the oil and gas industry have three legs placed in a 

triangular arrangement at the corners of the hull. Other elevating vessels, including those used in 

offshore construction, offshore wind, older drilling rigs, and smaller workover rigs, may have 

four or more legs. 

Three legged units have a number of advantages over four legged units (Geiger, 2004). Three 

leg units can carry more deck load while afloat than four leg units since they do not need to carry 

an extra leg and its associated jacking systems. Three leg units expose less area to wind, wave, 

and current loads, and are less sensitive to environmental conditions. Three leg units are also less 

expensive due to the reductions in steel weight (Mommaas and Blankestijn, 1984). The primary 

advantage of four legged units is greater stability and a reduction in the elevating time due to a 

simplified preloading procedure. 

8.4.2. Leg Length 

Water depth capability is one of the most important properties of a jackup and impacts its 

utility and cost. As water depth capability increases, leg length must increase, but many other rig 

parameters are also affected. Wang et al. (2009) examined the effects of water depth capability 

on the physical parameters of jackups and found that water depth was strongly correlated with 

leg length, hull breadth, hull depth, deck area and hull volume. Because of the broad influence on 

size-related parameters, water depth has a strong correlation with costs. 

8.4.3. Environmental Conditions 

Environmental conditions influence leg length, leg structure and hull size. Harsh 

environment rigs require longer legs to provide a greater air gap between the hull and sea level to 

allow for waves (Covellone and Thorson, 1985). Harsh environment rigs also require larger hulls 
87

to increase the spacing between legs and improve stability. The design of the leg chords is 

altered to minimize the effects of wind and current loadings, and the change in leg shape changes 

steel strength requirements of various leg components. 

The trend in recent harsh environment jackup designs has been to build extremely large, high 

specification vessels such as LeTourneau’s Gorilla class or Gusto MSC’s CJ70 series. The CJ70 

and CJ80 are harsh environment units and are approximately twice the weight of the moderate 

environment CJ46 and CJ50 (Table H.2). Figure H.5 compares the size of the CJ70 class rig to 

notable structures. 

8.4.4. Leg Type 

Jackup legs can be either single cylinders or trussed structures composed of three or four 

chords joined together by braces (Figure H.6). Trussed legs require a large number of welds and 

are more expensive to fabricate and take up more deck space than cylindrical legs; however, 

trussed legs have significant advantages over cylindrical legs. Trussed legs are usually lighter 

than cylindrical legs for the same bearing capacity which decreases steel costs and provides 

better stability while afloat. Trussed legs also expose less area to wind and water currents which 

reduces the likelihood of loss during storms (Macy, 1966; Vazquez et al., 2005; Mommaas and 

Blankestijn, 1984). 

Early jackup rigs frequently used cylindrical legs, but as rigs moved to deeper water 

cylindrical legs became less popular. Today, all newbuilt rigs are designed with trussed legs. 

Cylindrical legs are still used on liftboats and other offshore construction vessels and continue to 

exist in the legacy fleet. Cylindrical legs are common for water depths below 200 feet (Macy, 

1966) and for mat supported rigs (Geiger, 2004). 

8.4.5. Chord Number and Type 

There are several basic arrangements for leg chords (Figure H.7). The choice of chord shape 

is influenced by the required strength of the leg, but also by the way in which the racks of the 

chord interact with pinions in the elevating system (Mommaas and Blankenstijn, 1984), and 

wind and wave loading considerations as square chords are more susceptible to wind and wave 

loads than circular chords. Figure H.7 depicts half-round and teardrop chord designs. 

Tubular chords are typical of F&G, Gusto MSC, Keppel Baker Marine and some 

LeTourneau designs, and generally utilize two “half rounds” welded to a rack to make up a 

single chord with an outer diameter of approximately 15 to 30 inches. Teardrop chords simplify 

construction but result in heavier legs containing more steel and are typical of some LeTourneau 

designs (LeTourneau Technologies, 2010). Teardrop chords have a rack and elevating pinions on 

only one side of each chord while tubular chords have elevating pinions on either side of each 

chord. Opposed pinions balance forces and allow for a shorter and lighter jacking system 

compared to teardrop chords. 

Trussed legs may have either three or four chords. Most designs utilize three chords, but 

several popular models, including the LeTourneau Super 116E, use four chords. Four chorded 

legs are typically heavier and more susceptible to wind and wave loads than three chorded legs, 
88

however, there is more redundancy and lower loads on any single chord (Vazquez et al., 2005; 

Mommaas and Blankestijn, 1984). 

8.4.6. Rack Chocks 

After jacking, the vertical load of the rig may either continue to be supported by the pinions 

in the jacking system, or rack chocks may be inserted below the jacks to support the load (Figure 

H.8). Without chocks, the fixity between the hull and the legs is less than 100%, that is, 

movement between the hull and the legs will occur because the racks and pinions are not firmly 

connected. When chocks are inserted the fixity between the hull and the legs increases to 100% 

which allows for a reduction in the bracing required in the legs and a decrease in weight 

(Mommaas and Blankenstijn, 1984). Lighter legs are less expensive, reduce wind and wave 

loads, and increase variable loads by decreasing the lightship weight. However, smaller legs are 

more susceptible to breaking under uneven or increased loads, as in punch through. Most F&G, 

Keppel, Baker Marine and Gusto MSC rigs utilize chocks while most LeTourneau rigs do not. 

8.4.7. Footing Structure 

The legs may be connected either to a large mat-like structure attached to all the legs or to 

independent spudcans. In both cases, the purpose of the footing is to increase the surface area 

bearing the weight of the rig. Mat footings are box-like structures with approximately the same 

dimensions as the hull, usually with open areas so that they resemble an “A” (Figure H.9; Hirst 

et al., 1976). Mat foundations are typically subdivided to allow for selective ballasting to 

maintain neutral buoyancy throughout raising and lowering (Boswell and D’Mello, 1990). 

Mat foundations distribute weight over a larger area than spudcans and are superior to 

spudcans in soft sea beds but cannot be used on uneven or sloping sea beds, nor can they be used 

near pipelines (Geiger, 2004). By contrast, spudcan footings can be used on uneven or sloping 

sea beds and in a wide variety of soil types. Mat foundations allow for nearly complete fixity of 

the legs which allows for legs to be lighter and smaller, reducing wind and wave loads. Spudcans 

became more popular as rigs increased in size and water depth. As the water depth capacity of a 

rig increases, the distance between its footings must increase, which can lead to increasing steel 

costs for mat foundations. All modern newbuilds use spudcan foundations. 

8.4.8. Slot and Cantilevered Systems 

In a slot system, the drillpipe extends through a slot in the floor of the rig. In a cantilevered 

system (Figure H.10), the drilling rig extends off of one side of the rig, and in most modern rigs, 

cantilevers can move in two dimensions. The cantilever can extend or retract the drill floor 

perpendicular to the hull, and the drill floor can move parallel to the hull, either by moving the 

position of the drill floor relative to the cantilever or by skidding the placement of the cantilever 

on the hull (Blankenstijn et al., 2003). The cantilever can move the drill floor approximately 70 

to 90 feet perpendicularly and 15 to 30 feet parallel. Cantilevers add weight and cost to the rig, 

but allow jackup rigs to work over existing caissons and platforms. Cantilevers also increase the 
89

number of closely spaced wells that may be drilled, and allow more flexibility in “Swisscheesed” sea beds.8 All these factors increase the utility of the rig. 

8.5. JACKUP DESIGN CLASSES

Rig designs built in the U.S. over the past decade differ from those built elsewhere. 

LeTourneau designed rigs are dominant domestically (Table H.3) but are only a small portion of 

the international market. Table H.4 summarizes characteristics of rig designs commonly built in 

the U.S. and abroad. Three designs, the LeTourneau Super 116E, KFELS B Class and F&G JU 

2000 series, make up over two-thirds of 2012 orders. U.S. rig-building shipyards had three major 

customers in the 2000-2012 period (Rowan, Scorpion, and Perforadora Central), and all three 

firms have preferred LeTourneau rigs. Until 2011, Rowan owned LeTourneau and the 

construction of LeTourneau designed rigs at the Vicksburg shipyard reduced transaction costs for 

Rowan. Perforadora Central and Scorpion are both focused on the <350 ft water depth, moderate 

environment market, and the LeTourneau Super 116 and 116E are typically the lowest cost 

designs for this market. 

8.5.1. Common U.S. Built Designs 

The most common designs built in the U.S. are illustrated in Figure H.11 and their hull 

dimensions are depicted in Figure H.12. The Tarzan is the smallest class while the Super 116E 

and 240C are approximately the same size. The Super Gorilla is the largest rig class by a 

significant margin. 

LeTourneau Tarzan 

The Tarzan is specifically designed for shallow water (less than 300 ft) deep drilling (35,000 

ft) in moderate environments. The Tarzan was designed to provide HPHT drilling at a low cost, 

but the design has not been internationally successful. Four Tarzan class rigs exist, all built 

between 2004 and 2008 at the Vicksburg, Mississippi shipyard and all owned by Rowan. Unlike 

more traditional LeTourneau designs, the Tarzan uses three tubular chords with opposed pinions. 

LeTourneau Super 116E 

The LeTourneau Super 116E evolved from the LeTourneau 116C which was first built in 

1978 and is considered one of the workhorses of the industry. The first Super 116E was 

delivered in 2007 and eight have been delivered through 2011. The Super 116E is designed for 

moderate locations and 350 ft water depths and is well suited to shallow, moderate environments 

such as the Persian Gulf. Like many classic LeTourneau designed rigs, it has square legs, each 

with four teardrop chords. In recent years, several Super 116Es have been assembled at the 

AmFELS shipyard in Texas, and worldwide, 12 Super 116E rigs are under construction. In 2012, 

prices are typically less than $200 million and can be as low as $160 million for rigs designed for 

the Persian Gulf with water depth capabilities less than 250 ft. 

 

8 A Swiss-cheesed seabed is an area in which jackup rigs have previously worked. In these areas, depressions in 

the seabed left by earlier rigs can constrain the areas in which a rig may be positioned. 
90

LeTourneau 240C Workhorse 

Compared to the Super 116E, the LeTourneau 240C can work in deeper water with a greater 

variable load and a larger cantilever reach. The 240C uses a unique leg design with four tubular 

chords. The 240C is a relatively recent rig design, and only three have been delivered, and all of 

these were built at the LeTourneau shipyard for Rowan. In 2011, KS Energy ordered two 240Cs 

from a COSCO shipyard in China for $194 million each and these represent the first foreign 

sales of a 240C design license. 

LeTourneau Super Gorilla XL 

The LeTourneau Super Gorilla XL is among the largest jackups in the world (Figure H.13) 

and is capable of drilling in harsh environments in water depths up to 550 ft and drilling depths 

up to 35,000 ft. The Super Gorilla XL is an upgraded version of the Super Gorilla and the Bob 

Palmer is the only rig of its class. The Bob Palmer cost $326 million to construct and has been 

let for nearly $300,000 a day on a long-term contract with Saudi Aramco from 2011 to 2015. 

8.5.2. Common Internationally Built Designs 

A selection of the most commonly built international designs is depicted in Figure H.14. The 

Gusto MSC CJ70 is among largest rigs in the world, while the F&G JU 2000E is significantly 

larger than the KFELS B Class or PPL Pacific 375. 

KFELS B Class/Super B Class 

The KFELS Super B class is the most popular rig design in the world, and through 2012, 33 

have been delivered and 18 are under construction. Like other Keppel designs, the B Class is 

only built at Keppel’s yards. It is a high specification unit approximately equivalent to the 

LeTourneau 240C in capabilities and cost, and as of 2012, prices range from $180 to $210 

million. The B Class is available with a number of design variations including large spudcans to 

increase the allowable operating conditions and water depth capability of 300 to 425 ft. 

Gusto MSC CJ70

The Gusto MSC CJ70 is the largest and most expensive jackup under construction. It is 

capable of drilling in 492 ft of water in harsh environments. In 2011, Maersk ordered two CJ70’s 

for $500 million each and a third is under construction for North Atlantic Drilling (a subsidiary 

of Seadrill) for $530 million. All three rigs have secured initial contracts of three to five years 

with dayrates exceeding $350,000. The CJ70 is comparable to the LeTourneau Super Gorilla XL 

but has been more popular in recent years. 

F&G JU 2000 Series 

The Friede and Goldman JU 2000A, JU 2000E and JU 3000N are the most popular series of 

harsh environment jackups. The 2000A is limited to 350 ft water depths while the 2000E and 

3000N can drill in up to 400 ft of water. The 3000N is the newest and most capable rig in the 

series with first delivery in 2012. The 3000N is slightly more expensive (approximately $235 to 
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$245 million in 2012) than moderate environment designs with similar drilling capabilities, but 

far less expensive than other harsh environment jackups like the MSC CJ70 or LeTourneau 

Super Gorilla XL. 

PPL Pacific 375/400 

The PPL Pacific Class 375 and 400 (also called the Baker Marine Pacific Class) are moderate 

environment proprietary designs owned by PPL shipyard which is a subsidiary of Sembcorp. The 

design is built at shipyards owned by Sembcorp, and is also licensed to other shipyards. The 400 

class is capable of drilling in slightly deeper water than the 375 class (400 versus 375 ft) and can 

accommodate a larger crew (150 versus 120 people), but the rigs are otherwise similar and have 

the same hull dimensions, variable load and drilling depth. The 375/400 class is approximately 

similar to a LeTourneau Super 116E in terms of variable load and drilling depth, but generally 

has a slightly greater water depth capability. As of early 2012, three 400 ft units are under 

construction for Atwood, each at a cost of $190 million. 
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9. JACKUP RIG CONSTRUCTION 

Shipyards use labor, materials and capital to turn steel and third party equipment into rigs. 

Major work activities include welding, material handling, pipe fitting, machinery installation, 

electrical systems, and outfit materials. The construction requirements are relatively simple and 

consist of a large flat area of land adjacent to a waterway, several cranes, and a large enclosed 

space for performing high quality welds. Some type of launching system is also required to 

transfer the constructed rig to the waterway for transportation to market. In this chapter, we 

provide a high-level narrative and pictorial description of the jackup construction process with an 

emphasis on methods used in U.S. shipyards. 

9.1. WORKFLOW

The exact methods to assemble a jackup rig depend on the shipyard and rig specifications. 

Figure I.1 shows a generalized depiction of the work processes involved. Steel forms of different 

grades are received from one or more suppliers and are welded together to form the hull, legs, 

spud cans, liquid storage tanks, and quarters. Components are built separately and modularly and 

combined at different locations in the yard. The hull is assembled first and then the spudcans are 

placed through holes built into the hull. The first sections of the legs are attached and the living 

quarters and lower deck equipment added. The rig is then launched and the remainder of the leg 

sections and topside equipment is added. 

9.2. SPUDCANS

Spudcans are hollow steel structures generally made of 50 to 100 ksi steel.9 Spudcans may be 

fabricated away from the hull and lifted into holes (yokes) built into the hull, or the hull may be 

built around existing spudcans. Figure I.2 illustrates the two options. In the top image, the hull is 

being built around existing spudcans. In the bottom image, three spudcans (two in the foreground 

and one on the left of the image) are visible along with the hull; as the leg wells are completed 

the spudcans will be inserted. 

9.3. HULL

The hull of the rig is a barge-type hull with a flat bottom and sides constructed using 

stiffened plates (Figure I.3), which significantly simplifies construction compared to a traditional 

ship-shaped hull. A horizontal steel plate (1) is stiffened with bulb flats placed 2 to 3 ft apart. 

These sections (2) are supported by framing girders (3) that are spaced 6 to 9 ft apart and the 

horizontal sections span between vertical bulkheads (4) that are placed at areas of high loads 

(Rammohan, 2005). The hull is generally made of 30-50 ksi steel; however, small sections of the 

hull, especially the area around the legs, are made from high strength steel. 

Depending on the rig design and builder preference, the hull may be constructed modularly 

with different sections of the hull fabricated separately and assembled. Modules are designed to 

 

9 Steel is specified in terms of its yield strength, the maximum pressure a material can withstand before 

deforming. One ksi is equal to 1,000 pounds per square inch. 
94

utilize similar steel shapes to increase the repetition involved in construction. The use of modular 

construction is common in the shipbuilding industry and allows for parallel workflows, 

increasing shipyard output. Modular design is a relatively recent innovation in rig construction. 

Figure I.4 illustrates the early to mid-construction stages of three rig hulls. In the top image, 

much of the hull has been completed and machinery (shrouded in green) has been installed on 

the lower decks. In the bottom image, two hulls are under construction. On the right, a hull in the 

very early construction stages is shown; on the left, construction is more advanced. 

9.4. TOPSIDES

After the spudcans are in place and the hull is built, the jacking system and topsides 

containing living quarters and offices are installed (Figure I.5). The components of the jacking 

system are typically supplied by the design firm and included as part of the rig design package, 

with varying degrees of assembly at the shipyard. Outfitting work and the installation of 

machinery and equipment may be carried out before or after launching, but is most efficient if 

conducted prior to launch. 

9.5. RACKS AND HALF-ROUNDS

Chord structure varies by rig design, but in most three-chorded rigs, chords consist of a rack 

welded to semicircular “half rounds” (Figure I.6). The initial manufacturing stages of the racks 

and half rounds is conducted by third parties which convert high grade steel forms from steel 

mills into racks and half-rounds. 

Racks start as solid 5 to 7 inch plates of high grade quenched and tempered steel. This steel is 

then flame cut, a process in which a torch is used to ignite the steel. The plate is cut so that teeth 

are formed, making the rack. The rack may be up to 30 inches wide, root to root. The teeth of the 

rack are then pressed to exact measurements; the tolerance on rack teeth is typically 0.5 mm. Due 

to the high strength and width, rack steel is the most expensive steel used on the rig. Half-rounds 

start as flat plates of high grade steel. They are then cold pressed into half rounds by machine 

(Figure I.7). After the racks and half-rounds are machined, they are placed in shipping containers 

and delivered to the shipyard. 

9.6. CHORD ASSEMBLY 

The racks and half-rounds are delivered to the shipyard in 20 to 40 foot sections, with racks 

typically being in longer sections than chords. A section of rack is welded to two slightly shorter 

half-round chords so that several feet of rack extends beyond the end of the half-round. Two or 

three sections are fabricated simultaneously. The racks of these sections are welded together, 

leaving a several foot gap without a half-round. An appropriate section of half round is welded to 

the rack and then welded to the adjoining half-rounds. After individual chord sections are 

assembled, braces are welded to the chords and the chords are joined to form a 40 to 90 foot long 

section of leg. 
95

As a result of the high structural demands placed on rig legs, the steel used on leg chords 

must be of extremely high quality which can make welding difficult.10 The welding of the legs 

must be carried out in controlled shop conditions with submerged arc or gas metal arc welding 

techniques. Rather than use a flammable gas as in more familiar welding techniques, arc welding 

passes an electric current through an electrode. Welding consumables must also be tightly 

controlled to ensure quality. 

The most notable problem in welding leg joints is hydrogen cracking (embrittlement) which 

can be caused by the marine environment. Therefore, every weld on a leg must be inspected for 

cracks either by x-ray, ultrasound or another method of non-destructive testing. 

9.7. LAUNCHING

Rigs may be built in drydocks or adjacent to a quay. In the U.S. drydocks are not used. At the 

AmFELS shipyard in Brownsville, Texas, rigs are launched into the water via a slipway; at the 

LeTourneau shipyard in Vicksburg, Mississippi, rigs are “walked” into the water using a 

complicated and time consuming method of elevating the rig and moving dirt around the 

spudcans (Figure I.8). 

9.8. DERRICK AND CANTILEVER

The cantilever and derrick are constructed separately and modularly, then assembled and 

installed onto the rig following launching. The derrick is usually assembled at the shipyard by a 

specialized firm. Like the jacking system, prefabricated components of the cantilever may be 

supplied by the design firm and included as part of the rig design package. 

9.9. LEG ASSEMBLY

Early in construction and prior to launching, the first sections of leg are attached to the 

spudcans and the jacking systems. After launching, the remainder of the leg is added (Figure I.9). 

Depending on shipyard infrastructure, sections may be added directly to the top of the legs via 

crane, or sections may be added to the top of the legs using the lift capacity of the jackup After 

the legs are added, the jackup will be unable to pass under most bridges, thus, if the shipyard is 

located on a river (as is the case with the LeTourneau shipyard in Vicksburg, Mississippi), the rig 

will be floated to a yard with direct ocean access before the final leg sections are added. 

9.10. DELIVERY AND CLASSIFICATION

Following final outfitting, the rig is delivered to the buyer, usually at the builder’s shipyard.

Acceptance of the rig is typically based on satisfactory sea trials and certification by a 

classification society. Classification societies are independent, third party organizations that 

serve as a verification system parties with a special interest in the safety and quality of marine 

vessels. These may include regulatory authorities, insurance underwriters, owners, building yards 

and subcontractors, finance institutions and charterers. Classification societies provide a set of 

guidelines for design and construction and inspect shipyards during vessel construction to ensure 

 

10 The large number of alloys in high strength steel increases the hardenability of the steel which decreases the 

weldability. 
96

compliance to provide assurance that a set of requirements and standards are met during design 

and construction. Each classification society has its own rules for classification; however, many 

aspects of classification are similar and are meant to ensure the safety against hazards to the 

vessel, personnel and environment. The American Bureau of Shipping (ABS) is the most 

common classification society both in the U.S. and internationally, but Det Norsk Veritas is also 

used depending on customer preference. 
97

10. MODU RIG EQUIPMENT 

MODUs are equipped with marine and mission systems. Marine equipment is found on all 

marine vessels and is used to operate the vessel at sea (engines, pumps, electrical systems), while 

mission equipment is used to drill wells and consists of drilling equipment similar to that found 

on land rigs, as well as additional systems specialized for the offshore environment. In this 

chapter we provide a pictorial overview of the mission equipment used on offshore rigs to 

familiarize the reader with the essential components and their primary function. For a more 

detailed discussion of rig equipment and function see (Jahn et al., 2008) or (Azar and Samuel, 

2007). Marine equipment is not specialized in nature and is not discussed. 

10.1. MODU SYSTEMS

MODUs are designed to drill and workover wells in the offshore environment, and 

specification sheets as shown in Figure J.1 provide engineers the necessary data to select the rig 

capable of drilling their wells. A large number of specialized systems are required to drill a well. 

For bottom supported rigs, critical systems include those used to position and elevate the rig 

above a well or platform; to provide mechanical force on the bit; to control the pressure inside 

the wellbore; to detect and control blowouts; to handle and assemble tubulars; and to handle and 

store liquid and bulk materials. Floating rigs require additional systems including station keeping 

systems, systems to install subsea equipment and systems to compensate for the vertical 

movement of the rig. 

Four systems common to all floaters and jackups are described: systems that provide force 

for drilling, mud systems to control the pressure inside the well, safety systems to control the 

flow of hydrocarbons, and support systems to handle tubulars (Figure J.2). 

10.2. DRILLING 

During drilling, two forces act on a drillbit; a rotational force (torque) imparted by the rig, 

and a downward force due to gravity. A topdrive is used to turn the drillstring which is used to 

turn the bit. The drillstring is composed of drillpipe and the bottomhole assembly. The drillpipe 

is a steel tube that transmits torque from the rig to the bit and allows for the circulation of drilling 

fluid into the well. The bottomhole assembly is composed of the bit, drill collar, and various 

measurement or mud circulation tools. The drill collar is a particularly heavy steel pipe that is 

used to add weight to the drillstring. 

The topdrive is suspended from the top of the derrick by a hook (Figure J.3). As the bit bores 

deeper into the earth, the topdrive descends down the derrick. When the topdrive nears the 

drillfloor, drilling is suspended. The drillpipe is disconnected from the topdrive and a new 

section of drillpipe is connected between the topdrive and the existing drillsting. The topdrive is 

raised to the top of the derrick and drilling resumes. This process is referred to as “making a 

connection”.

Periodically, drilling is suspended so that the borehole may be cased with steel pipe. Casing 

is used to protect freshwater zones, isolate formations and avoid the loss of drilling fluids. 

During casing operations, the drillstring is removed from the well and large diameter steel pipe is 

inserted into the well and cemented into place. 
98

Drilling fluids are circulated down the well and perform several functions. Reservoirs are 

under high pressures and if these pressures are not controlled, hydrocarbons will flow from the 

reservoir into the well during drilling, potentially causing a blowout. Drilling fluid regulates the 

pressure inside the well and keeps formation fluids from entering the well. Drilling fluids also 

lubricate the bit, and transport the drill cuttings up to the rig. Drilling fluids pass down the well 

through the drillpipe and return to the rig through the annulus between the drillpipe and the 

casing (or open hole if the well is not yet cased). Mud pumps are used to transport drilling fluids 

and solid control systems are used to remove drill cuttings from the mud. 

10.3. DRILLING EQUIPMENT

The drilling systems of a rig are shown in Figure J.3. The primary systems include the 

derrick, topdrive, drawworks, crown and travelling block. A kelly and rotary table are also 

incorporated on most MODUs, but are less efficient than the topdrive system and are not widely 

used. Drilling equipment consists of two related systems: the rotary system and the block-andtackle system. The rotary system is comprised of the topdrive (or rotary table and kelly) and 

provides torque on the drillbit. The block-and-tackle system is the pulley system that is used to 

move equipment out of the well. 

10.3.1. Derrick 

A derrick is a pyramidal steel structure (Figure J.4) that is used to support the vertical loads 

acting on the drill bit and to provide a working space for the vertical assembly and storage of 

tubulars. At the top of the derrick is the crown block which is a part of the block and tackle 

system used to lower and lift the drillstring; the crown block is connected to the travelling block 

which moves up and down the derrick and is connected to the hook. Derricks are rated according 

to the vertical loads they can tolerate and modern MODU derricks are designed to support hook 

loads of 1.5 to 2 million pounds. Many modern rigs have a dual derrick or other offline capacity. 

Without offline capabilities, all major activities require successive access to the drill floor. 

Offline capacity allows for building of bottomhole assemblies and drillpipe and casing stands 

adjacent to the main drill floor allowing for parallel workflows, reducing the overall time to drill 

a well. 

10.3.2. Topdrive

The topdrive is the machine that provides the rotational force required to turn the drillbit. The 

top drive consists of one or more electric motors connected to a short section of pipe called a 

quill which is connected to the drillstring (Figure J.5). The topdrive is suspended from the hook, 

and is free to travel up and down the derrick. Rotary tables and kellys are still used as an 

alternative to a topdrive on older rigs, but topdrives are more efficient because they enable 

drilling to be performed with three-joint stands of drill pipe and reduce the frequency of stuck 

pipe. Top drives are specified in terms of their horsepower and torque; typical values are 1,500 

hp and 80,000 lb ft at 100 rpm for a jackup rig. 

10.3.3. Drawworks 

The drawworks is a winch placed near the bottom of the derrick (Figure J.6). The drawworks 

is the prime mover of the block and tackle system and is connected to the crown block. It 

consists of an electric motor, brakes and related systems. The drawworks provides the vertical 
99

force necessary to move loads out of the wellbore and to resist the weight of the drillstring. 

Drawworks are specified in terms of horsepower and static load capacity; typical values for a 

MODU are 6,000 hp and 2.5 million pounds static load capacity. 

10.4. MUD SYSTEMS

Drilling fluids (mud) circulates through a system of pumps, high pressure hoses, and 

particulate removal systems (Figure J.7). Starting at the mud pumps, mud travels through the 

standpipe and rotary hose. The rotary hose is a flexible line that moves up and down with the 

drilling equipment and connects to the topdrive or kelly. Mud passes down the drillpipe through 

the bit and after picking up the cuttings, passes up through the annulus between the drillpipe and 

the borehole. Once at the surface, the mud passes into a flowline and arrives at the mud treatment 

equipment to remove gas, salt, silt and cuttings. After treatment, mud is discharged to mud tanks 

and re-enters the pumping system. 

10.4.1. Mud Pumps 

Mud pumps are the prime movers of the mud circulation system (Figure J.8). They are 

typically “triplex” pumps composed of three separate pistons driven by one or more electric 

motors. Mud pumps are specified in terms of horsepower and maximum operating pressure. The 

maximum operating pressure helps to determine the ability of the pumping system to control a 

well. Typical values are in the range of 3,000 hp and 7,500 psi and most modern MODUs will 

have three or more pumps. 

10.4.2. Solids Control 

When drilling mud circulates up the borehole it contains drill cuttings. These cutting are 

detrimental to the mud pump and must be removed. A series of machines are used for this 

process including shale shakers, degassers, desanders, desilters and mud cleaners. Mud cleaning 

is conceptually simple and primarily utilizes the differential weight of the gasses and particulates 

entrained in the fluid. 

A shale shaker is the first step in mud cleaning and is composed of a vibrating screen sieve 

(Figure J.9); mud flows over the screen and solids in the mud with a diameter greater than the 

size of the screen are retained. Fluids and small diameter solids pass through the screen and 

continue through the mud treatment system. The screen sizes on a shale shaker are variable and 

the mud passes through several screens before progressing to the next treatment stage. 

After the largest solids are removed, the mud passes to a degasser which applies a vacuum to 

the mud to remove gasses dissolved in the fluids. The mud then proceeds to the desander and 

desilter. The desander and desilter are hydrocyclones (Figure J.9); mud is fed tangentially into an 

inverted cone and the centrifugal force induced by the flow causes the heaviest solids to migrate 

to the bottom of the cone (where they are disposed of) and the lighter fluids to exit through the 

top of the cone. The mud passes through a number of desanders and desilters in series with the 

diameter of the cone determining the size of the particles removed. 

The liquid underflow from a desilter may be further processed by the mud cleaner. The 

desilter allows some amount of usable mud to be passed through the bottom of the hydrocyclone. 
100

A mud cleaner processes the underflow from the desilter using a vibrating sieve. Mud cleaners 

are employed to conserve weighting agents and to recover liquids from oil- or synthetic-based 

muds which cannot be environmentally discharged. 

10.5. BLOWOUT PREVENTER

A blowout preventer (BOP) is a piece of safety equipment installed between the drilling rig 

and the wellbore (Figure J.10). On jackups, it is located on the vessel below the drill floor, while 

in deepwater applications it is usually placed on the seafloor. In the case of a loss of well control, 

the function of the blowout preventer is to form a physical barrier to stop the flow of 

hydrocarbons up the wellbore. A number of methods exist for creating this physical barrier, and 

most rigs use a combination of several methods in a single BOP stack. Annular BOPs are 

elastomeric rings that can be mechanically squeezed to form a seal around a drillpipe, casing, or 

other tubular element or an openhole. In contrast, a ram BOP is a system which uses two large 

diameter, hydraulically powered cylinders, one on each side of the wellbore, to force together 

two ram blocks (Figure J.11). Ram blocks may be designed to seal around a drill pipe (a pipe 

ram), over a wellbore without a drillstring (a blind ram), or to shear through the drill pipe (a 

shear ram). Blowout preventer stacks are specified in terms of their type (annular or ram) and 

operating pressure (typically in the range of 10,000 psi). 

10.6. PIPE HANDLING

During drilling, a variety of pipes must be moved from the pipe deck to the drill floor. Once 

on the drill floor, pipe must be turned from a horizontal to a vertical position and sections of pipe 

must be mated together to form stands. Stands are stored in fingerboards, then moved from the 

fingerboard to the wellbore and inserted into the well. Historically, much of this work was 

performed manually or with simple machines requiring a large degree of human intervention. On 

modern rigs, this activity has been mechanized and automated to improve efficiency and reduce 

the potential for accidents. 

There are a variety of machines which perform pipe handling and most of the activities on 

the drill floor. An iron roughneck (Figure J.12) performs pipe handling in the immediate vicinity 

of the well and makes connections between the pipe already in the well and the next stand of 

pipe. A catwalk machine (Figure J.13) moves pipe from the pipe deck to the drill floor while a 

pipe deck machine (Figure J.14) moves pipe around the pipe deck. An integrated control system 

is used to operate all of these systems from the drillers’ cabin (Figure J.15). There are a variety 

of methods for handling pipes, but in general these systems are composed of gantry cranes, 

articulated mechanical arms, and tracked systems. 
101

11. JACKUP RIG WEIGHT RELATIONS 

The weight of a rig is an important variable in cost estimation and determines the amount of 

steel required in construction. Rig weight is generally considered proprietary, however, because 

it indicates design benchmarks and performance metrics that are central to the competitive nature 

of the industry. Standard methods for predicting ship weight based on its physical attributes have 

been used for several decades (Molland, 2008), but given the structural differences between 

jackup rigs and ships, these techniques do not adequately predict rig weight. The purpose of this 

chapter is to estimate the lightship displacement of jackups based on an empirical analysis of rigs 

built over the past three decades. 

11.1. WEIGHT MANAGEMENT

Weight is a primary design factor and is associated with rig capabilities. Larger rigs have 

greater variable loads, can support more powerful drilling equipment, and operate in more severe 

conditions. Weight is an important factor in design and is linked to fabrication costs. As more 

steel is added to a rig, material costs and fabrication expenses increase. Complex tradeoffs are 

involved with weight management, and because so many interdependent factors are involved in 

the design process, it is difficult to quantify the effects of weight on cost (Halkyard, 2005; Ellis 

and Shirley, 2005). Weight is also critical in determining rig stability and the size and design of 

the spudcans (Endley et al., 1981; Vazquez et al., 2005). 

11.2. WEIGHT FACTORS

The weight of a jackup rig is primarily determined by the water depth, drilling and 

environmental capability of the rig, and rig design. Rig weight is also commonly called lightship 

displacement and refers to the weight of the rig with all machinery installed but without fuel or 

other cargo. We use these terms interchangeably. 

11.2.1. Water Depth 

As the water depth capability of a rig increases, the length of the legs increase, but at some 

point, incremental leg length cannot be added to a given hull design and the hull must be 

enlarged. As a result, water depth is correlated with a number of physical descriptors including 

leg length, hull breadth, hull depth, deck area and hull volume (Wang et al., 2009). Figure K.1 

illustrates for three popular rigs the correspondence between water depth and weight. 

11.2.2. Drilling Depth 

In order to increase the drilling depth capability of a rig, designers must make allowances for 

more powerful drilling equipment, stronger cantilevers and greater variable loads. Larger and 

heavier rigs are required to accommodate more numerous and powerful drilling systems and 

heavier cantilever loads. 

11.2.3. Environmental Capability 

Harsh environment rigs are heavier than moderate environment units. For the same water 

depth capability, harsh environment rigs must have longer legs than moderate environment units 

to increase the air gap. The legs and spudcans of harsh environment rigs are built to a more 
102

robust standard than moderate environment rigs and use higher quality and thicker steel. Harsh 

environment units may also have greater variable loads than moderate units to reduce the 

frequency of resupply, and this requires a larger, heavier rig. Since jackups are particularly well 

suited to harsh environment operations, some contractors have built harsh environment jackups 

with 500 ft water depth capabilities to extend the use of jackups into waters typically limited to 

semis. Ultra-high specification jackups are much heavier than moderate environment units; for 

example, the Gusto MSC CJ70 weighs 28,000 tons, approximately twice the weight of a typical 

moderate environment unit. 

11.2.4. Rig Design 

The tradeoffs designers make between the grade and quantity of steel impact rig weight 

(Massie and Liu, 1990). Either larger quantities of lower grade steel or smaller quantities of 

higher grade steel may be employed. For example, a rig designer may increase the number of 

braces in each leg, but decrease the yield strength of the steel. Using lower grade steel will 

increase weight, but may result in lower costs. Table K.1 illustrates the variation in leg unit 

weights. Leg density typically varies from 2 to 6 tons/ft and is greater in harsh environment rigs. 

Rigs may employ rack chocks to transfer the vertical load from the leg racks to the hull. 

Without rack chocks, the load is held by the pinions in the jacking system. The use of chocks 

increases the fixity between the hull and the legs and allows for a reduction in the bracing in the 

legs, reducing leg weight (Mommaas and Blankenstijn, 1984). Most F&G, Baker Marine, 

Keppel, and Gusto MSC rigs utilize chocks, while most Letourneau rigs do not. 

11.3. DATA SOURCE 

Information on rig weights are not widely available and are generally considered proprietary 

because they are an important aspect of design. We assembled data from 31 rigs representing 21 

designs and identified their environmental class (harsh vs. moderate), water depth, hull length, 

hull width, build year and designer (Table K.2). Data were collected from the academic 

literature, specification sheets and industry personnel. In some cases, lightship displacements 

were estimated as the transit displacement minus the transit variable load to supplement the 

dataset. Transit displacement is the weight of the rig when prepared for wet tow. Transit variable 

load is the weight of material and ballast required during a wet tow. The use of transit 

displacement data introduces bias in the analysis, but errors are believed to be less than 10% of 

true lightship displacement. When more than one data point was available from a single rig 

design, the displacements were averaged to ensure that the data points were independent. 

11.4. SUMMARY STATISTICS

The distribution of lightship displacement from the sample set (Figure K.2) has an average of 

11,479 tons (range 5,569-28,600 tons) with an average water depth capability of 314 ft (range 

250-450 ft). For harsh and moderate environment rigs, the average displacement was 17,575 and 

10,195 tons, respectively. The age distribution was bimodal with 10 of the 31 rigs built after 

2008, and 19 of 31 built before 1985; the average age was 22 years. 
103

11.5. SINGLE FACTOR MODELS

Figure K.3 shows the relationship between displacement and water depth and water depth 

squared. Water depth explains 57% of the variation in lightship weight, but water depth squared 

is a slightly better predictor of rig weight. The three harsh environment designs all fall above the 

regression line suggesting that they weigh more than average moderate environment rigs for the 

same water depth capability. 

Figure K.4 shows the relationship between hull dimensions and rig weight. In this case, hull 

dimensions predict about half of the variation in rig weight, but unlike the water depth 

relationship, there is no trend of harsh environment rigs being heavier than moderate 

environment rigs for a given hull dimension. The three harsh environment designs fall at the 

right end of the graph suggesting larger hulls than the other rigs in the sample. 

11.6. WEIGHT RELATION

A linear regression model was developed to estimate rig weight using hull length and breadth 

(width), water depth capability, designer, environmental class (harsh vs. moderate) and build 

year as predictor variables. Hull length times hull breadth entered the model as an interaction 

term to proxy the area of the hull. Designer and environmental class were modeled as indicator 

variables. Variables were checked for multicolinearity, and because breadth was correlated with 

length and environmental class, these variables were not permitted to enter the same model. 

The best model included terms for water depth, water depth squared, and hull length times 

hull width: 

D = 49,316 – 3,233WD + 0.563WD2+ 0.12LB,

where D is lightship displacement (tons), WD is water depth capability (feet), and L and B are 

the length and breadth of the rig (feet), respectively. Environmental class, designer and build 

year were not significant predictors. 

The model explained 91% of the variation in displacement and all terms were significant. 

The inclusion of the length and width interaction term explained slightly more variation than 

either the length or width terms individually, and the coefficients were insignificant when the 

interaction term and the length or width terms were included together. 

Figure K.5 depicts the model output for fixed lengths and breadths. Water depth is positively 

correlated with weight, and as water depth increases, the slope of the relationship increases. In 

reality, width and breadth are not constant with increasing water depth. 

The harsh environment indicator variable was not a significant predictor of weight which is 

likely due to the fact that only three of the 21 designs were harsh environment units. The lack of 

data reduces the ability of the model to accurately predict the weight of harsh environment rigs. 

Build year and designer were also not significant predictors, which could indicate physical 

similarity in rig designs over time and between designers. 
104

11.7. LIMITATIONS

Small sample size reduces the confidence in the results and inflates model fit (Nelson and 

Kim, 1993). However, because the total number of rig designs in the world are limited and the 

sample does include most of the rigs commonly built in shipyards, including the F&G L780 Mod 

II, the LeTourneau Super 116, the Baker Marine 375 and the Gusto CJ 70 X 150 the relations are 

expected to reasonably reflect real-world conditions. Additional predictor variables could be 

examined, but since the model already predicts over 90% of the variation in weight, the weight 

relation is adequate for aggregate assessments and gross benchmarking studies. Additional error 

may be introduced because the lightship displacement of some vessels was based on estimated 

values and a number of different sources were utilized which may estimate lightship 

displacement differently. Deficiencies in the weight reporting may be partly offset by the 

averaging of multiple records. 
105

12. CAPITAL, LABOR, AND MATERIAL REQUIREMENTS FOR JACKUP 

CONSTRUCTION IN THE U.S. 

Jackup rig construction in the U.S. generates an average of $374 million in direct revenue 

each year and over the past decade has ranged between $129 and $986 million. About 2,500 

people are directly employed by the industry annually, and although employment is small 

relative to other offshore industries, the jackup rig construction market is important regionally 

and culturally because of its long tradition in the region. A top-down approach is used to 

estimate labor and material requirements of rig construction. The cost to construct a rig is 

decomposed into five elements–drilling equipment, rig kit, labor, material, and profit–and for 

each element, a cost module is developed. 

12.1. RIG CONSTRUCTION

12.1.1. U.S. Market 

Two U.S. shipyards build rigs: the Keppel AmFELS yard in Brownsville, Texas, and the 

LeTourneau yard in Vicksburg, Mississippi. Between 2000 and 2012, the Vicksburg yard 

delivered 11 rigs and the Keppel AmFELS yard delivered 14 rigs. Approximately two jackups 

have been delivered each year over the past decade at a total value of $3.9 billion. 

12.1.2. Cost Components 

During the contracting process, shipyard personnel estimate the costs of construction to 

develop a bid price. Rig construction requires capital, labor and materials, and a budget for each 

cost component is developed. Capital is recovered through a profit margin assessed on each rig 

built; labor and material costs are estimated using an engineering-based approach and quotes 

from industry suppliers. 

Capital 

The capital costs of shipyard operation are minimal and consist of open land with access to a 

waterway, enclosed work spaces for welding and fabrication, several cranes, and a launching 

system. In Asia, launching is frequently conducted via drydock while in the U.S., launching is 

performed via slipway or “walking”. 

Labor 

Labor is required to fit, weld, and assemble steel components, attach drilling equipment, and 

certify, inspect and manage construction. Major work requirements during rig building include 

welding of steel components, assembly of piping systems, installation of equipment, outfitting, 

material handling, engineering and management. 

Materials

Materials include steel, drilling equipment, the rig kit, engines and generators, and various 

other manufactured goods. Steel is used in rig construction because of its strength, durability, 
106

corrosion resistance, weldability and price. Drilling equipment includes the derrick, top drive, 

BOP, mud and pipe handling systems, and other systems, and is frequently purchased as a 

package from an integrated supplier (Figure L.1). The rig kit includes the jacking systems, 

design license, and other components sold by the design firm. In the case of LeTourneau rigs, 

kits typically include leg components, cranes, and capstans. Engines and generators provide the 

power and electricity to power a rig and are an essential component of reliable operations. Other 

material includes outfit material, piping, electrical system components, pumps, and safety 

equipment. 

12.2. SUPPLY CHAIN DISTRIBUTION

Labor costs directly enter local economies, but material costs are distributed across greater 

geographic regions and often represent a greater percentage of the total cost in rig construction. 

Figure L.2 shows the major manufacturing centers for steel and equipment used on rigs built in 

U.S. yards. 

For LeTourneau designed rigs, leg steel is fabricated in Longview, Texas. Lower strength 34 

or 51 ksi steel is widely available throughout the shipbuilding industry and is typically ABS A, 

ABS AH36 or similar grades.11 Globally, several hundred mills produce ABS certified products 

including 36 in the U.S., mostly in the Midwest, Southeast, Pennsylvania and West Virginia 

(ABS, 2011).

Table L.1 shows the major suppliers of equipment in U.S. built rigs over the 2000-2010 

decade. Engines are typically sourced from Caterpillar. Caterpillar marine engines are assembled 

at the Lafayette, Indiana and Griffin, Georgia manufacturing facilities. Blow out preventers are 

sourced from Cameron, Hydril or National Oilwell Varco (NOV). Derricks are from Woolslayer, 

Loadmaster or NOV, and most other drilling equipment from either Lewco (a division of 

LeTourneau) or NOV. 

Much of the drilling equipment used in jackup rigs is assembled in and around Houston, 

Texas, and other locations in Texas and South Louisiana. Cameron operates manufacturing 

facilities in Ville Platte, Louisiana; NOV operates manufacturing facilities in and around 

Houston, Texas, and Pampa, Texas; Woolslayer (now Lee C. Moore, A Woolslayer company) 

operates a manufacturing facility in Tulsa, Oklahoma; Loadmaster operates a manufacturing 

facility in Broussard, Louisiana; and LeTourneau drilling systems operates manufacturing 

facilities in Longview and Houston, Texas. 

 

11 ABS steel is steel that is fabricated to ABS specifications. ABS A steel is 34 ksi and ABS AH36 is 51 ksi, 

where ksi represents kilopounds per square inch and is used to indicate the pressure at which a steel will begin to 

deform plastically. 
107

12.3. COST ESTIMATION AND ADJUSTMENT

A top-down approach is used to estimate the cost components of rig construction. Since most 

rigs built in the U.S. in recent years have been LeTourneau Super 116E’s, we emphasize this 

design, but the methodology we develop is completely general. The cost to construct a rig is 

broken into five elements: drilling equipment, rig kit, labor, material and shipyard profit (Figure 

L.3). For each of the five elements, a cost estimation module is developed. 

The drilling equipment and rig kit modules apply fixed prices and do not vary with other 

input. For all other modules, the output cost is a function of user input and module parameters. 

User input includes capital costs, lightship displacement, and installed power. If any of these are 

unknown, empirically derived relations may be substituted. Module parameters include wages 

and productivity assumptions. 

All price assumptions and output costs are in 2010 dollars and reflect average market 

conditions in the 2005 to 2010 period. To apply the estimation procedure to a future time period, 

output is multiplied by a forecast adjustment factor. The adjustment factor is given by It/I2010, 

where It is the value of the appropriate BLS producer price index at time t, and I2010 is the index 

value in 2010 (Table L.2 and Figure L.4).

12.4. CAPITAL EXPENDITURES

The total capital cost of the rig is user input for several component modules. In many cases, 

capital costs may be known and input directly; if unknown, they are estimated based on rig 

specifications. 

12.4.1. Data Source 

Cost data for all rigs ordered in the U.S. from 1996 through 2011 were assembled from the 

commercial data provider RigLogix. Contract costs are publicly reported because most drilling 

operators are public companies and rig construction represents a significant investment for the 

firm. The use of public data is subject to reporting bias because costs may not be reported 

similarly and may differ in the inclusion of owner-furnished equipment or finance costs. All data 

were inflated to 2010 dollars using the BLS shipyard producer price index (USDOL, BLS, 

2011b) and the order date. 

12.4.2. Rig Construction Cost 

In Table L.3, the nominal and inflated construction costs of all U.S. built rigs ordered 

between 1996 and 2011 are depicted. A total of 26 rigs were built in the U.S. during this time 

and all rigs are independent-leg cantilever units, and all but three were LeTourneau designs. 

Inflation-adjusted prices range from $101 to $326 million with an average of $180 million. 

Jackup costs by water depth and design class is shown in Table L.4. Costs generally increase 

with increasing water depth capacity, and within a water depth class, costs are reasonably similar 

because of similar build locations and the contract execution date. In some cases prices range 

significantly for similar rigs. For example, Offshore Defender, Resolute, Courageous, Intrepid
108

and Vigilant are all LeTourneau Super 116s, built at the Brownsville, Texas shipyard and ordered 

in 2005 and 2006. Defender and Courageous cost $87 million each while the Resolute and 

Intrepid cost $143 million. The difference in cost results from contract options and timing. 

Defender and Courageous were built as options executed in 2005 but based on contracts written 

in 2004, while the other rigs were new contracts written in 2005 and 2006 at a time of higher 

demand. 

12.4.3. Regression Model 

Jackup costs are estimated using a multi-factor regression model based on descriptor 

variables specific to the rig class, user preferences, and data availability. Predictor variables 

include hull length, hull width, order date, drilling depth, maximum water depth, and 

environmental design. Costs are expected to be positively correlated with all variables. 

Hull width was correlated with hull length, water depth, order date and harsh environment 

variables. Multicolinearity was also found between the harsh environment indicator and the hull 

length and order date variables. These variables were not allowed to enter the model together. 

The best model for the 26 rigs in the sample was specified by: 

Cost = –96 + 0.42 * WD + 0.003 * DD + 103 * HARSH, 

where Cost is in million dollars, WD is water depth (ft), DD is drilling depth (ft), and HARSH is 

an environmental indicator variable (1 if harsh, 0 otherwise). All the coefficients are of the 

expected sign and statistically significant and the model explained 77% of the variance in cost. 

According to the generalized relation, every 100 feet of increased water depth capability 

increased construction cost by $42 million; each 1,000 feet of drilling depth capability increased 

cost by $3 million, and the premium for harsh environment rigs was $103 million. 

12.5. LABOR COST MODULE

12.5.1. Labor Cost Relation 

Labor cost is determined as the product of the number of man-hours required and the average 

hourly wage: Labor cost = Hours * Wage. The number of hours required is estimated from the 

capital costs divided by the productivity. The labor cost relation is thus: 

,*

Pr

cos

cos Wage

oductivity

Capital ts tLabor



















where capital costs are measured in dollars ($), productivity is measured in dollars of value 

produced per hour of labor ($ output/h labor), and wages are measured in dollars per hour ($/h). 

Capital cost is a user input. Wages and productivity are input based on empirical data. 

12.5.2. Wages 

Hourly wages in rig building are expected to be similar to the ship building industry because 

of the commonalities in the work requirements. In Table L.5, the costs of labor at U.S. shipyards 

including fringe benefits are depicted in inflation-adjusted terms (USDOL, BLS, 2011a). The 
109

inflated dollars per hour (the last column of Table L.5) is calculated assuming all employees 

work an average of 2,000 hours per year. In 2007 and 2008 data, employees worked an average 

of 1,940 and 2,033 hours per year, respectively. Labor costs in U.S. shipyards appear relatively 

stable over time and range from 35 to 38 $/h from 2002 to 2009. 

12.5.3. Productivity 

The number of man-hours required to construct a jackup rig depends on the rig type, nation 

of build, preassembly status, and shipyard. Jackup productivity in U.S. yards is confidential and 

to estimate the labor requirements in support of rig construction a suitable proxy must be 

employed. Steel weight or compensated gross tonnage12 has been used to proxy the man-hours 

required to construct a ship (Rashwan, 2005; Carreyette, 1977; Lamb and Hellesoy, 2002; Bruce, 

2006), however, jackup rigs are structurally different from other ship types and their 

compensated gross tonnage factors are not well defined (Lamb et al., 1995).

We use the average revenue generated by one unit of labor for the entire U.S. shipbuilding 

industry to proxy the relationship between labor and revenue for the rig building industry. This 

method assumes that productivity is similar between the U.S. rig and shipbuilding industries 

which is likely to be reasonable as long as the technology employed in shipbuilding is roughly 

similar to that used in rig building. This assumption is difficult to validate given the data 

constraints associated with rig construction, but provides a consistent means to estimate market 

revenue and infer employment in support of rig construction, and is amenable to the available 

data. 

In Table L.6, the annual shipment value from all U.S. shipyards is divided by the annual 

number of hours worked to yield productivity in terms of shipyard revenue per hour of labor. 

One hour of labor generated between $92 to $109 of vessel value from 2002 to 2009, or on 

average $100 of vessel value, which is approximately equal to the productivity in Keppel’s 

Singaporean yards in 2010 (Wong and Chang, 2011). The labor required to construct a vessel is 

estimated by multiplying vessel cost by the inverse of productivity. Thus, for a $200 million 

jackup rig we would expect approximately 2,000,000 man-hours of labor to be required in 

construction. 

These estimates are consistent with anecdotal reports and conversations with rig construction 

engineers (Sheridan, 2009; Fogal, 2009) and appear to approximate operating practices. For 

example, Keppel AmFELS delivered a $190 million LeTourneau Super 116E rig in 2009. It was 

reported that rig building employed up to 470 people and required 1.5 million man-hours (Clark, 

2010). Other industry reports suggest 1.25 to 1.5 million man-hours are required at AmFELS for 

Super 116E construction. LeTourneau’s Vicksburg shipyard employed approximately 1,000 

people (including contractors) during its peak employment in 2007 and 2008 (Hitchens and 

Barrett, 2009). In every year since 2003, LeTourneau has delivered one rig. Assuming each 

 

12 Compensated gross tonnage is a unit of measurement developed by the Organization for Economic 

Cooperation and Development (OECD) that allows relative comparison of shipbuilding outputs across countries and 

vessel types. Compensated gross tonnage is defined by A*GTB, where GT is a vessel’s gross tonnage, and A and B 

are class-specific conversion factors derived by OECD. 
110

worker works 2,000 hr per year, a LeTourneau rig would require approximately 2 million manhours. 

12.6. MATERIAL MODULE 

12.6.1. Steel Cost Sub-Module 

Categorization

The two grades of steel that are typically used in rig construction include low-carbon steel for 

structural elements such as legs, decks, railings, walkways and deck plating, and high-strength, 

low-alloy steel for critical components and extreme climate conditions (Marshall, 1986). We 

categorize steel weight into three components: hull steel (typically 34 to 51 ksi), leg steel 

(typically 100 ksi), and miscellaneous steel (typically 72 to 90 ksi). 

Steel Cost Relation 

Steel costs are estimated separately for each component and summed. Costs are calculated as 

the weight of steel (in tons) multiplied by the price per ton. Each component (x = hull, legs, 

miscellaneous) is assumed to be a proportion of lightship displacement: 

Steel costx = Percent weightx * Lightship displacement * Steel pricex. 

Weight Distribution 

Lightship displacement is a user input. The proportion of lightship displacement attributable 

to the leg, hull and miscellaneous steel is estimated from known weight distributions of a sample 

of rigs (Table L.7). Although the sample size is small and based on both generic and actual rigs, 

interval ranges are not expected to vary significantly across rigs. Approximately 20 to 30% of a 

rig weight is made up of steel in the legs and spudcans, while 40 to 60% is made up of steel in 

the hull, jacking houses and cantilevers. 

Table L.8 depicts the weight distribution of a 300 ft moderate environment rig. Fifty-three 

percent of the rig is composed of 34 to 51 ksi steel in the hull, 23% is composed of 100 ksi steel 

in the legs, and 7% is composed of miscellaneous 72 to 90 ksi steel throughout the rig. From 

Tables L.7 and L.8, we assume that for a moderate environment 300-400 ft water depth rig, 20 to 

30% of steel is leg steel (100 ksi), 40 to 60% is hull steel (34 to 51 ksi), and 5 to 10% is 

miscellaneous steel (72 to 90 ksi). 

Steel Price Assumption 

Steel prices vary with changing market conditions and depend on yield strength, shape and 

quantity ordered. Deliveries are negotiated on a per-rig basis and are not publicly reported, 

however, hull steel prices are expected to be similar to North American A36 plate which varied 

from 267 to 1,080 $/ton between 2001 and 2011. We assume that leg steel costs between 4,000 

and 7,000 $/ton, hull steel costs 700 to 1,100 $/ton, and miscellaneous steel costs 1,000 to 1,500 

$/ton. Hull steel costs may be estimated with confidence because prices for shipbuilding steel are 
111

widely reported, although highly variable over time. Prices for leg steel are poorly known 

because they are not widely tracked. Miscellaneous steel is a minor cost component. 

12.6.2. Engine Sub-Module 

Engines and generators are a large component of material costs. While most rigs use a 

version of the Caterpillar 3516, a number of versions and options are available and prices vary 

with market conditions. Based on a 2012 survey of generator set prices, generator sets are 

assumed to cost 400 to 600 $/kW delivered. Table L.9 provides the installed power on selected 

rig designs. If the actual power of a rig is known, it may be input; otherwise, power is assumed to 

range from 8 to 11 MW. 

12.6.3. Other Material Module 

Other materials include piping, wiring and other electrical equipment, pumps, heating and 

cooling systems, kitchen equipment, lifeboats and other safety equipment, capstans, cranes, 

navigational equipment, furniture and other outfit materials. Consumables include paint, 

electricity, fuel, and welding supplies. The costs of these supplies are difficult to generalize, but 

in the shipbuilding industry they typically account for 20 to 25% of total vessel costs. We 

assume material costs for rigs represent a similar proportion of total costs as ship construction. 

12.7. RIG KIT MODULE

Rig kit costs depend on the rig design and the scope of the kit and are purchased separately. 

All kits include a design license and jacking systems. In LeTourneau rigs, kits also include leg 

components, anchor winches, cranes and certain components for the cantilever and spudcans, but 

the precise components are negotiable. Between 2007 and 2009, LeTourneau reported income of 

$418 million for work on 15 to 18 rig kits, giving an average cost of $23 to $29 million per kit 

during this time. Recent contract costs for LeTourneau Super 116E rig kits are shown in Table 

L.10. Rig kits are assumed to cost between $25 and $45 million per rig. Rig kits are likely to 

scale in proportion to the size of the rig, and for rigs larger than the Super 116E, kits will be 

more expensive. 

12.8. DRILLING EQUIPMENT MODULE

Drilling equipment is not included in the rig kit. Drilling equipment includes derricks, 

mudpumps, topdrives, blow-out preventers, drawworks, automated pipe handling systems, and 

solids control systems. Drilling equipment costs vary with the drilling capabilities of the unit. 

Recent contract costs for jackup rig drilling equipment systems are shown in Table L.11 and 

Table L.12 shows the costs of specific drilling components adjusted to 2010 dollars. Costs for a 

complete drilling package range from $20 to $70 million. Note that the two highest costs 

reported in Table L.11 are both for Gusto MSC CJ70 jackups, a high specification, harsh 

environment design. For rigs such as the Super 116E, costs for a complete drilling package range 

between $20 and $50 million. 
112

12.9. PROFIT MODULE

Profit margins are the proportion of revenue attributable to net income. The Gulf of Mexico 

jackup construction market competes with international markets with lower labor costs and high 

productivity, and as a result, profit margins in the region are expected to be low on a relative 

basis. For example, from 2006 to 2010, Rowan’s drilling products division (principally 

composed of the LeTourneau shipyard) received an average profit margin of -2.7% and a 

maximum of 9.7%. In contrast, Keppel’s marine division averaged a 13.6% profit margin over 

the same period. Low profit margins do not adequately protect a firm from the risks of cost 

overruns and we assume that profit margins below 5% are unsustainable. Profit margins above 

10% are unlikely due to international competition. We select a range of 5 to 10% as 

representative of the industry and apply this range in subsequent calculations. 

12.10. ILLUSTRATION

We illustrate the cost estimation procedure using a hypothetical moderate environment 

LeTourneau Super 116E constructed in the Gulf Coast in 2010. We assume an operational water 

depth of 375 feet, a drilling depth capability of 30,000 feet, and hull dimensions of 243 by 206 

feet. 

12.10.1. Capital Costs 

Application of the capital cost model requires the user to substitute the operational water 

depth (375 ft) and drilling depth (30,000 ft) into the capital expenditure regression model to 

obtain $164 million. Capital cost is the primary input in the labor, material and profit modules. 

12.10.2. Labor Costs 

Labor requirements are determined by the product of the capital cost and the inverse 

productivity metric. For hourly compensation ranging between 34 and 38 $/hr and productivity 

between 90 and 100 $/hr, labor costs range from $51 to $69 million (Table L.13). 

12.10.3. Material Costs 

The water depth (WD, 375 ft), length (L, 243 ft) and breadth (B, 206 ft) of the rig are 

substituted into the weight relation from Chapter 11 to yield 12,575 tons. Table L.14 partitions 

this mass among rig components based on the assumed weight distribution described for leg steel 

(20-30%), hull steel (40-60%) and miscellaneous steel (5-10%). Steel costs range from $14 to 

$37 million and are dominated by the costs of leg steel because of its high unit costs, even 

though the hull contributes the majority of the weight. 

Installed power is assumed to range from 8 to 10 MW and is multiplied by the unit cost (400 

to 600 $/kW) yielding generator costs of $3 to $6 million. Other material costs are assumed to 

range from 20 to 25% of capital costs, or $33 to $41 million. 
113

12.10.4. Rig Kit and Drilling Equipment Costs 

The rig kit for LeTourneau rigs are assumed to be fixed cost between $25 and $45 million. 

Drilling equipment is assumed to cost $20 to $50 million. 

12.10.5. Profit Margins 

Profits are assumed to be 5 to 10% of capital costs, or $8 to $16 million. 

12.10.6. Cost Distribution 

Table L.15 shows the distribution of construction cost along with cost estimates provided by 

industry participants. The costs of leg steel are included in the rig kit. Approximately one third of 

costs are associated with shipyard labor and over half of costs are associated with materials, 

mostly in the drilling equipment package and rig kit. The total expected costs range from $145 to 

$237 million with an average of $191 million. This matches closely with the $195 million 

purchase price of a LeTourneau Super 116E ordered from the AmFELS shipyard in 2011, and 

with estimates provided by industry personnel. 

12.11. U.S. JACKUP MARKET SIZE 

12.11.1. Market Revenue 

The annual inflation-adjusted value of the U.S. jackup rig industry is shown in Table L.16 by 

shipyard. The total value of deliveries ranged from $129 million in 2005 and 2006 to $986 

million in 2008. The three year average of delivery value is a better measure of annual industry 

revenues because payments for shipbuilding are spread throughout the construction process. On 

average, the rig building industry generates $374 million in revenue each year. Table L.16 and 

Figure L.5 show the distribution of estimated revenue at the two jackup shipyards in the U.S. In 

the early part of the decade, the LeTourneau Vicksburg yard dominated rig construction, but by 

2005, the AmFELS Brownsville yard had surpassed LeTourneau in revenue. 

In 2011, the Vicksburg shipyard was sold to Cameron, a flow equipment manufacturer, along 

with LeTourneau Technologies drilling equipment manufacturing division. The Vicksburg 

shipyard delivered the Joe Douglas to Rowan in late 2011, and as of early 2012, the Vicksburg 

shipyard has no newbuild orders and has stopped building rigs. Barring a significant change in 

market conditions, work in the yard is unlikely to resume. 

12.11.2. Labor Market 

U.S. shipyard productivity varies between 90 and 110 $/h of revenue generated for each hour 

of input labor. Using this productivity range and the three year average value of revenue, the 

total annual employment in the rig building industry is given in Table L.17. Between 2000 and 

2010, we estimate between 800 and 3,900 people were directly employed by the jackup 

construction industry. Table L.18 shows the distribution of employment by shipyard and matches 

anecdotal reports of employment (Clark, 2010; Hitchens and Barrett, 2009). 
114

12.11.3. Relative Size

The jackup construction market in the U.S. is small relative to related offshore industries. 

Other industries supporting the offshore oil and gas industry include the OSV construction 

market, the drilling equipment manufacturing market, and the drilling contractor market, and all 

three of these markets are significantly larger than the rig construction industry. In 2011, the five 

largest U.S. based drilling contractors (Transocean, Noble, ENSCO, Diamond and Rowan) 

received $19 billion in revenues, and the three largest U.S. based players in the drilling 

equipment manufacturing market (NOV, Cameron and Dril-Quip) received $22 billion in 

revenue. Between 2007 and 2010, the U.S. OSV construction industry is estimated to have 

received average annual revenues of $969 million compared to $615 million for the rig 

construction industry over the same period (Kaiser and Snyder, 2010). 
115

13. CONSTRUCTION COST FACTORS 

Many factors influence rig construction cost. Market conditions, design type and class, 

construction shipyard, and rig specifications are the primary factors. Contract type, shipyard 

productivity, and scale economies also influence cost, but are either unobservable or more 

difficult to ascertain the nature of their impact. The goal of this chapter is to describe the primary 

factors that impact rig construction costs. 

13.1. MARKET CONDITIONS

Prices are determined by the demand for rig construction services and the number of 

shipyards capable of supplying these services. Drilling contractors demand newbuilt rigs when 

dayrates and utilization rates make investment criteria positive. But only a small number of 

shipyards around the world are capable of building rigs; and during periods of high demand, the 

supply of rig construction services saturates the market, leading to backlogs and price increases. 

From 2000 to 2011, for both jackups and floaters, there was little activity early in the decade 

and prices were low (Figure M.1). The number of jackups ordered during this time numbered 

less than 10 per year. For floaters, there were three orders in 2001 and two orders in 2002. As 

orders increased in the middle part of the decade, prices rose. Following the 2008 recession, 

orders declined markedly, but prices only declined marginally, reflecting long backlogs and the 

expectation that a decline in orders would be short lived. 

13.2. MATERIAL PRICES

13.2.1. Cost Distribution 

Building a rig requires steel, labor, drilling and other equipment. The manner in which cost is 

distributed across these categories determines the variation in construction cost by rig class, 

complexity and time. Shipyard location plays a key role. In China, labor costs are low and are 

likely to represent a small proportion (on the order of 10%) of total costs. By contrast, U.S. labor 

costs are high and may account for as much as 30% of total costs. Steel costs are highly variable 

over time, and when prices are high, the percentage values in will tend to reside at the upper end 

of their ranges. 

13.2.2. Steel 

Steel is the main component of rigs and material prices have an impact on newbuild costs. 

On a proportional basis, jackup steel is usually a larger component of cost (10 to 20%) than in 

floaters (<10%). Steel prices are specified on a per ton basis and vary regionally with steel 

quality and shapes (Figure M.2). Rigs are constructed using a variety of steel strengths and are 

built throughout the world, and no single steel price reflects costs for all rigs. However, the vast 

majority of rigs are built in Asia, and the Asian steel price index13 is a reasonable proxy for the 

rig construction market. Both rig prices and the steel index grew over the course of the decade at 

approximately the same rate, and are correlated (Figure M.3). The steel price index explains 70% 

 

13 The Asian steel price index is created by the steel industry tracking firm MEPS and is the arithmetic average 

of steel plate prices in four Asian countries based on a survey of industry participants. 
116

of the variation in average jackup rig prices. No significant relationship is observed between 

floater prices and steel prices. 

13.2.3. Equipment Prices 

Engines, cranes, generators, drilling equipment, and dynamic positioning systems are 

significant components in rig costs. These are all third-party materials purchased by the rig 

builder and assembled on site or at another location. The drilling equipment package is the 

largest equipment expenditure, and typically costs $20 to $70 million for jackups and $100 to 

$200 million for floaters (or on the order of 10 to 30% of total costs). Non-drilling related 

equipment range over similar cost intervals; and together, drilling and other equipment typically 

range from 30 to 60% for jackups and floaters (Table M.1). 

Drilling and equipment costs are influenced by steel prices to the extent that the majority of 

the equipment is made from steel, but more importantly, are influenced by demand from the oil 

and gas and commercial shipping industries. Labor cost is also a large component in equipment 

manufacturing costs. 

The oil and gas field machinery equipment index14 can be used to proxy the costs of the 

drilling equipment installed on MODUs; the finished goods index proxies the overall rate of 

inflation experienced by manufactures (Figure M.4). While both indices are based on U.S. 

products, the oil equipment index is applicable to global MODU prices because much of the 

drilling equipment installed on MODUs is sourced from the U.S. Throughout the 1990’s the oil 

and gas index grew gradually and in line with the finished goods index, but in the mid-2000s the 

oil and gas index increased rapidly, outpacing the overall rate of inflation, suggesting that the 

increase in rig prices is due in part to an increase in the costs of drilling equipment. 

The relationship between average global jackup and floater prices and the BLS oil and gas 

field equipment index between 2000 and 2011 is shown in Figure M.5. The fact that the steel 

price index was a poor predictor of floater costs, while the equipment index explained 82% of 

the variation in prices suggests that equipment costs are a larger factor in overall prices than steel 

costs for floaters. The equipment and steel indices are themselves correlated (R2= 0.84) and 

likely to be influenced by many of the same global factors, however, their influence on the costs 

of rigs is largely independent since each index impacts a separate shipyard budget category. 

13.3. EXCHANGE RATES

Contracts for rig construction are denominated in U.S. dollars, but costs at international 

shipyards may be in U.S. dollars, euros, Chinese yuan, South Korean won, or Singaporean 

dollars. For example, labor and steel costs at a South Korean shipyard may be in South Korean 

won while drilling equipment costs may be in U.S. dollars. For the rig builder, as the value of the 

U.S. dollar rises, the value of a contract increases. From the perspective of a rig buyer, a strong 

 

14 The oil and gas field machinery and equipment price index is created by the BLS based on a monthly survey 

of industry firms. It is based on a basket of products including drawworks, blowout preventers, rotary equipment, 

drill bits, risers, production equipment, etc. Onshore and offshore equipment is included (USDOC, Census, 2004).
117

U.S. dollar lowers newbuild costs at international shipyards. Thus, when the dollar declines 

relative to a local currency, an increase in costs is expected. 

13.4. LABOR 

Labor costs and productivity are important drivers of shipyard costs (Wong and Chang, 

2011). The costs of shipbuilding labor in the U.S. and Korea are roughly similar and about three 

times the labor costs of Singaporean yards. South Korea compensates for relatively high labor 

costs with advantages in productivity over Singaporean and U.S. yards. 

Over the past decade, both labor costs and productivity have increased in Singaporean and 

South Korean yards (Figures M.6 and M.7), and the combination of these two factors will 

determine the contribution of labor to total costs. The revenue generated per dollar spent on labor 

is shown in Figure M.8. In the U.S., each dollar spent on labor generates approximately three 

dollars of revenue, consistent with labor costs accounting for approximately one third of total 

costs. In Singapore and South Korea, each dollar spent on labor generates approximately seven 

to ten dollars of revenue, suggesting labor costs make up on the order of 10 to 15% of total costs 

for rigs built internationally. 

13.5. DESIGN CLASS

Newbuild jackup designs range from $159 to $530 million for water depths between 200 to 

492 feet and variable deck load (VDL) capability of 3,750 to 7,000 tons (Table M.2). The 

KFELS B Class, Letourneau 116E and F&G JU-2000E are the most popular designs. In general, 

there is relatively little variation in cost between rigs of the same design, but some designs 

exhibit more variation in water depth capacity and price than others. The Letourneau Super 116E 

class is especially variable because several rigs are being built for the Persian Gulf market where 

water depth capability is not at a premium. 

Semisubmersible newbuilds range from $460 to $771 million for water depth capacity 

ranging from 1,640 to 10,000 feet and VDLs between 5,000 and 22,000 tons (Table M.3). 

Operating displacement varies between 42,000 and 62,000 tons. There is more variation in costs 

between rigs of the same design than for jackups, and this may reflect increased customization. 

Most of the units are sixth generation ultra-deepwater rigs; however, the GM 4000 is designed 

for drilling in mid-water regions or well workovers in ultra-deepwater, while the GVA 4000 

NCS is intended for harsh environment drilling in mid-water. Both of these rigs were designed to 

provide lower capital and operating costs in regions in which the capabilities of ultra-deepwater 

rigs were not required. 

Drillship newbuilds range from $550 million to $1.2 billion for displacements ranging from 

45,000 to 112,000 tons in part reflecting differences in oil storage capabilities, and VDLs 

between 15,000 and 24,000 tons (Table M.4). The Samsung 10000 and 12000 and the Gusto 

P10000 are the most popular designs ad are capable of storing small amounts of oil 

(approximately 140,000 bbl15) during early production, while the Gusto PRD12000 and Huisman 

designs exclude oil storage to reduce ship size and operating and capital costs (Duhen et al., 

 

15 One bbl of crude oil weighs approximately 0.15 tons, so 140,000 bbl storage is equivalent to 21,000 tons. 
118

1998). Stena and Keppel have developed a drillship to drill slimmer, less expensive wells but to 

date, these smaller designs have not been as popular as the larger designs (Humphreys, 2011). 

13.6. RIG SPECIFICATIONS

Rig designs vary in drilling capabilities, VDL capacity, maximum water depths, and 

environmental criteria. As vessel specifications increase, costs rise, for all other factors held 

constant. 

13.6.1. Structural Weight 

Weight is associated with rig capabilities. Larger rigs have greater variable loads, can support 

more powerful drilling equipment and can operate in more severe conditions. Weight is an 

important factor in design and is linked to fabrication costs; as more steel is added, material costs 

and fabrication expenses increase. However, complex tradeoffs are involved with weight 

management, and because so many interdependent factors are involved, it is difficult to quantify 

the effects of weight on cost (Halkyard, 2005; Ellis and Shirley, 2005). 

13.6.2. Water Depth 

Water depth is a primary determinate of jackup costs. The legs of a jackup are made of 

expensive high grade steel, and as water depth capacity and environmental criteria increase, so 

will the costs of construction. For example, leg chord steel in the U.S. Gulf Coast cost $6,000/ton 

in 2012; for an average sized jackup, material costs for leg steel may range from $12-30 million. 

Wind and wave forces act in proportion to leg length, and above a certain threshold, a rig 

cannot be extended to deeper water by simply extending its legs. Instead, a new and larger rig 

design is required (Covellone and Thorson, 1985; Marshall, 1986; Salama, 2005). 

For drillships and semisubmersibles, water depth capability is not as strongly correlated with 

costs because the rigs are floating units; and with the exception of the drilling risers and anchor 

handling systems, do not have elements that pass through the water column. Increased water 

depth is associated with increased costs for risers, riser tensioners, mud pumps, anchor winches, 

drill strings and mud storage facilities (Shu and Loeb, 2006). 

13.6.3. Operating Environment 

Rigs capable of operating in harsh environments are heavier and more expensive than 

moderate environment rigs. Harsh environment jackups have longer legs to increase the airgap, 

and as leg length increases, the distance between the legs and the size of the hull must also 

increase. Similarly, semisubmersibles built for harsh environments must have longer and thicker 

columns than moderate environment units which in turn increases costs. Drillships are not 

typically designed for operation in harsh environments, but interest in Arctic exploration has led 

to harsh environment designs, and can cost over $1 billion to build. 

13.6.4. Equipment Specifications 

As the drilling depth capability of a rig increases, more robust pumping units and safety 

systems are required to handle the higher formation pressures and temperatures, increasing costs. 

The power, storage and VDL capacities determine the maximum drilling equipment that may be 
119

installed on the rig. Drilling depth may be used to proxy equipment specification, but it is the 

actual specifications that determine rig cost. Important specifications include the hook load, riser 

pressure, rated pressure and diameter of the blow-out preventer, degree of offline capability, 

storage capabilities, number and power of mud pumps, mud tank capacity, number and flowrate 

of shale shakers, desilters, desanders, cementing unit operating pressure, and capacity of the 

BOP handling system. 

13.7. CONTRACT TYPE AND OPTIONS 

Rigs may be built by drilling contractors with or without a firm contract commitment from an 

E&P company. When building a rig speculatively, contractors may approach negotiation more 

aggressively and be less willing to pay than when building a rig with a contract commitment. 

Building a rig on speculation increases risk and the firm may only be willing to accept this risk 

when market conditions (e.g. recession) put downward pressure on costs, making the investment 

more likely to be profitable over the life of the rig. 

For example, in 2011, Maersk Drilling ordered two MSC CJ70 jackups on speculation for 

$500 million each; two months later, Seadrill ordered the same rig for $530 million after 

receiving an initial contract. Similarly, in June 2008, Seadrill ordered a Pacific Class 375 rig on 

speculation from PPL shipyard for $215 million; the next month Egyptian Drilling received a 

contract and ordered the same rig from the same shipyard for $220 million. These data are 

anecdotal and the differences small, but the general concept is clear. 

Rigs ordered on option allow a contractor to purchase one or more additional rigs at a fixed 

price simultaneously with their initial order or at a later time. Typically, options must be 

exercised within a year of contract signing and the cost of optioned rigs is frequently higher to 

account for the risk of inflation, and because the option has inherent value for the contractor by 

locking in future newbuilding capacity. 

13.8. SHIPYARD CHARACTERISTICS

Shipyards vary in their rig building experience, labor costs, supply chain management, tax 

structure and government subsidies, construction methods, reputation and degree of integration 

(Gray, 2008). Many of the major rig shipyards maintain their specialization with proprietary 

designs. Keppel-FELS and LeTourneau each have their own line of jackup rigs and while these 

yards can and do build other designs, they have gained significant experience by building 

specific rigs and may be able to do so at lower costs than other yards (Wee, 2008). Similarly, 

many yards have long-term contractual relationships with rig operators; these operators often 

prefer a particular design class or company and they may order several identically designed rigs 

to be delivered from the same yard which will likely lead to cost reductions through learning. 

Large rig shipyards exist in Singapore, China, India, South Korea, Russia, the United States 

and the United Arab Emirates. These countries differ markedly in their labor practices and costs, 

tax structures, the importance of rig/shipbuilding to the overall economy, and the degree of 

government intervention (Koenig et al., 2003) which contributes to construction cost differences 

across countries. Competition acts in the opposite direction however, and forces high-cost 

shipyards to offer similar prices and accept lower returns to win work, reducing price 

differences. 
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Shipyards differ in the methods in which they construct rigs based on their level of 

automation, subcontracting, and the degree of serial production line usage. The particular method 

of fabrication and assembly is unique for each yard and rig and depends upon space and 

equipment availability. Singaporean shipyards are particularly space limited. South Korean yards 

are less space limited and use a sophisticated “mega-block” method of ship construction in which 

very large ship sections are fabricated separately and then assembled in a floating dock (Wang 

and Chong, 2011). A high degree of specialization will likely lead to reduced costs and enhanced 

quality control standards, but this is only feasible for yards with a constant supply of orders. 

13.9. BACKLOGS 

The amount of time between when the rig is ordered and delivered is important in 

determining costs and risks to both parties (Moyst and Das, 2005; Duffey and Van Dorp, 1998). 

The time to construct a rig depends on a number of factors but is typically 18 to 36 months; 

however, the time between contract finalization and rig delivery can significantly exceed the 

construction time due to shipyard backlogs. During construction, the buyer is required to make 

payments on the rig but does not receive income which can create cash flow problems for 

buyers. Additionally, as the time between ordering and delivery increases, market conditions 

may change, creating risk for the buyer and seller; for the buyer, rig utilization and dayrates may 

decline while for the seller, steel, labor or material costs may increase. When there is a 

particularly long delay between contract finalization and the start of construction, a cost 

escalation clause may be included. 
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14. NEWBUILD AND REPLACEMENT COST FUNCTIONS 

Rigs are the primary assets of drilling contractors and their newbuild and replacement costs 

are frequently required in corporate planning and financial valuation. Cost functions provide 

insight into the factors that influence costs and are used by investors, government agencies, and 

other stakeholders to evaluate newbuild programs or the value of an existing rig or fleet. The 

purpose of this final chapter is to develop generalized newbuild and replacement cost functions 

based on rig attributes. Robust multi-factor cost models for jackups and semis are derived, but 

for drillships suitable models could not be developed due to the homogenous nature of the units 

and the small variation in costs in the sample. For drillships, average cost and standard 

deviations adequately describe the sample statistics. Water depth was the single best predictor of 

rig cost and replacement cost models explained larger proportions of variance than newbuild 

models which is likely due to the manner in which cost estimates were performed. 

14.1. DATA SOURCES

Newbuild costs are widely reported in public documents, and because most contracts are 

turnkey in nature, the values are accurate representations of the costs paid by owners to 

shipyards, excluding financing and interest expenses. The replacement value of rigs is more 

ambiguous and is estimated by market intelligence firms, drilling contractors and insurance 

companies using specialized algorithms and expert opinion. Replacement costs reflect the costs 

to replace a rig with a new asset of similar quality. Newbuild and replacement cost data from 

Jefferies (Jefferies and Company, Inc., 2009) was applied in our analysis. 

We focus on the physical factors related to the capability of the rigs rather than more difficult 

to quantify time-dependent factors such as market conditions. The time period of analysis is 

fixed at October 2009 and the cost functions derived are reflective of this time period. It is 

relatively simple to adjust for a future period. For a near-term future period, cost can be adjusted 

using an appropriate index or alternatively, if the samples are updated, a new cost function can 

be derived and the model re-estimated. 

For newbuilds, the sample set includes 39 jackups, 35 semis and 37 drillships and 

represented the majority of rigs under construction in 2009-2010. A number of jackups were 

under build by National Oil Companies or on speculation by shipyards; cost information on these 

rigs were not available. The replacement cost sample includes 282 jackups, 149 semis and 35 

drillships and included active, ready- and cold-stacked units. The world fleet at the time of 

analysis was 470 jackups, 200 semis and 50 drillships, and so the sample is reasonably 

representative of the total inventory. Rigs not included in the sample are those owned by small 

private operators and National Oil Companies where information on the replacement costs is not 

available or reported. 

Jefferies and Company, Inc. (2009) provides basic information on rig operating water depth, 

delivery year and design. These data were supplemented with information on drilling depth and 

environmental operating conditions from RigZone, contractor websites, trade press literature and 

design descriptions from naval architecture firms. No adjustments for inflation are made since 

cross-sectional analysis was performed and all costs are reported in 2009 dollars. 
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14.2. SUMMARY STATISTICS

14.2.1. Average Cost 

Summary statistics on the average cost and water depth of the rig samples are shown in Table 

N.1. Compared to existing rigs, the average jackup in the newbuild sample costs more ($225 

versus $142 million) and was capable of drilling in deeper water depths (362 versus 293 ft). 

Average newbuild semis and drillships costs were $553 and $672 million, respectively, relative 

to fleet replacement values of $366 and $470 million. 

14.2.2. Cost Variation 

The large dispersion in newbuild jackup costs is primarily attributable to four harsh 

environment rigs capable of drilling in over 400 ft of water (Figure N.1). These rigs each cost 

over $450 million whereas most other rigs in the sample cost approximately $200 million. There 

is also wide cost variation among semis due to the presence of harsh environment designs, but 

less variation in drillship newbuild costs with all drillships costing between $585 and $750 

million. The coefficient of variation for newbuild jackups is significantly greater (0.46) than for 

semis (0.18) or drillships (0.08). The lack of variation among the drillship sample indicates that 

regression models are unlikely to be able to distinguish the factors that make drillships unique 

and capture cost variation. Replacement cost is uniform across rig types which is likely due to 

the manner in which replacement cost is estimated and similar lifecycle and upgrade regimes 

(Figure N.2). 

14.2.3. Rig Age 

The distribution of rig ages in the world fleet circa 2009 is shown in Figure N.3. The drillship 

fleet is younger and has a smaller vintage range than the semisubmersible or jackup fleet and age 

is less likely to be a reliable predictor of drillship replacement cost. A primary difference 

between the replacement and newbuild data is the age range of the vessels. In the newbuild data, 

all rigs were built in the 2009-2012 period, while in the replacement models rigs were built over 

several decades. Age may impact the replacement costs because for all else equal, as technology 

improves, costs should decrease. For example, a 300 ft water depth jackup with a drilling depth 

capability of 25,000 ft would have been considered a high specification unit in the early 1980’s 

and may have commanded a premium; by the late 2000’s, such a rig would be standard and may 

be priced at a discount. 

14.2.4. Water Depth and Environmental Capability 

Water depth and operating environment are related determinants of newbuild costs for 

jackups (Table N.2). In harsh environments, jackups with water depth capabilities of 350 to 400 

ft cost 90% more than jackups with 300-350 ft water depth capabilities; in moderate 

environments, the price premium is 23%. For semis, there is a significant water depth price 

premium in harsh environments, but a less notable premium in moderate environments; harsh 

environment, ultra-deep water semis (>7,500 ft) are 56% more expensive than harsh, midwater 

units (<2,500 ft), but in moderate environments, the price premium between ultra-deep and 

deepwater (2,500 to 7,500 ft) is only 4%. Small sample sizes may influence these results, but in 

general, large cost differences are found in harsh environment rigs because of design variability 

and country of build differences. 
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14.2.5. Country of Build 

Table N.3 shows the distribution of rig costs by country of origin for newbuilds. Korea 

(35%), Singapore (24%), and China (20%) captured 80% of the newbuild market in 2009 and 

continue to reflect current newbuild share. Singapore is the primary jackup builder, China is 

dominant in semi construction, and Korea dominates drillship construction. In both the jackup 

and semi market, there is significant international competition, but in 2009, nearly all drillships 

were built in Korean yards. Singaporean shipyards have slightly lower costs than their 

competitors; in every market in which Singaporean yards have market share, the average cost at 

Singaporean yards is less than in any other nation. No other nation has a notable cost advantage. 

14.3. MODEL DEVELOPMENT

14.3.1. Function Specification 

Econometric techniques are common in maritime valuation assessments because of their 

versatility, theoretical foundation and robust estimators. Newbuild cost functions and second 

hand market valuations is an active area of research for shipbuilding (Mulligan, 2008; Adland 

and Koekebakker, 2007; Dikos, 2004; Tsolakis et al., 2003; Dikos and Marcus, 2003) but has not 

been studied in the context of offshore drilling rigs. We specify newbuild and replacement cost 

models using a multi-factor linear functional: 

C(U) = α0 + ∑αiXi,

where C(U) represents the cost of rig class U and the number and selection of the descriptor 

variable Xi is specific to the rig class, user preferences, and data availability. Variables examined 

include designed environmental conditions, rig specifications, market conditions, age, upgrades, 

life extensions, and related factors. The coefficients of the model formulation are estimated 

through ordinary least-squares regression and α0 can be interpreted as a fixed-term component. 

In general, we report the results of several models for each rig class to highlight differences and 

compare predictors. When multiple models are presented, the “best” model is identified on the 

basis of R2. 

Cost are estimated with and without the fixed-term component and the effects of forcing α0 to 

be zero were examined because models without a fixed cost component allow for the 

determination of the relative contribution of each variable. Whenever the intercept term in a 

regression model is set to zero, the model fit R2 and statistical significance improve due to the 

manner in which R2 is calculated.16 There is no meaningful way to interpret R2

 values, however, 

and they are not reported for regressions through the origin. The standard error (SE) of a 

regression going through the origin is meaningful and we report SE to allow for model 

comparisons (Hahn, 1977). 

 

16 In a regression with an intercept, the R2 is the proportion of variance explained by the regression (R2 = 1- 

SSE/SST, where SSE is the variance not explained by the regression and SST is the total variance). SST is 

determined by summing the squared differences between the observed values and the mean value (SST = 

 ̅ 

 

, where Yi is the ith observation and ̅ is the mean). However, when the regression is forced through the origin, 

the SST becomes the sum of the squared differences between the observed values and zero (SST = 

 

) 

while SSE does not change. This will increase the SST and therefore the R2 (Eisenhauer, 2003).
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14.3.2. Variable Description 

For newbuilds, the following variables were considered: operating water depth, year of 

delivery, drilling depth, environmental design conditions (harsh or non-harsh environment), 

variable deck load, and country of build. For replacement cost, water depth, year of delivery, 

years since upgrade (effective age), upgrade status, and environmental design conditions were 

examined. Variable deck load was not considered in the replacement cost analysis due to data 

limitations. For jackup replacement and newbuild costs, water depth squared was examined 

because higher-order terms of deadweight have previously been shown to be a reliable predictor 

(Mulligan, 2008) and because rig weight is better correlated with water depth squared (Chapter 

11).

Water depth, drilling depth and variable load are continuous variables. Delivery year is a 

discrete variable that enters the newbuild model as X rather than 200X, while for replacement 

costs, the actual year of delivery is used. Year of delivery precludes using the derived relations in 

a predictive manner for a future time period. When qualitative variables are used they are 

referred to as indicator or dummy variables and they take the value 0 or 1; e.g., rigs designed to 

operate in a harsh environment can be categorized using an indicator variable: HARSH = 1, NOT 

HARSH = 0. 

14.3.3. Expectations 

Water depth and drilling depth are expected to be positively correlated with costs for all rig 

types. Water depth should have a pronounced impact on jackup costs because of the leg length 

correspondence and the increased cost to build. Newbuild costs are also expected to increase 

over time because the period of analysis is relatively short (2009 to 2012) and contracts made for 

later deliveries were finalized in early 2008, before commodity prices fell, credit markets 

tightened, and shipyard demand was high. Harsh environment rigs are expected to cost more than 

non-harsh environment rigs and costs are expected to be higher in developed countries such as 

Korea and the U.S. and lower in China and India. We also expect that newer rigs and more 

recently upgraded ones will be more expensive to replace than older rigs that have not been 

upgraded. 

14.4. NEWBUILD COST MODELS

14.4.1. Single Variable Models 

Single variable linear regression models using water depth, year of delivery and drilling 

depth capability were examined. The relationships behaved as expected in most cases with 

increases in water depth, drilling depth and build year having a positive influence on cost, 

however, most relations were not significant. The only statistically significant relationship 

involved water depth and jackup costs (Figure N.4). 

14.4.2. Jackups

Multivariate newbuild cost models were specified using an environmental indicator 

(HARSH), water depth (WD, ft), and water depth squared (WD2, ft2) terms. Variables for 

country of build, drill depth or delivery year did not add explanatory power and were excluded. 
125

The impact of variable deck load was minor and was not included in the best model. The best 

model took the form: 

Newbuild Cost = α0 + α1HARSH + α2WD + α3WD2

.

All costs are reported in million dollars and the results of several variable combinations are 

shown in Table N.4. Model A explained the largest portion of the variation in newbuild costs and 

contains both water depth and water depth squared terms of opposite signs. Figure N.5 illustrates 

the output of model A; in the figure, the upper line is the model for harsh environment rigs, while 

the lower line is the model for moderate environment rigs. Costs increase at an increasing rate 

with water depth, consistent with our a priori expectations. 

Models B and C compare the effects of the water depth and water depth squared terms and 

suggest that water depth squared is a slightly better predictor than water depth. In models A 

through C, negative and large positive intercepts are inconsistent with a priori expectations. 

Therefore, we examined the effects of constraining the y-intercept (α0) to zero in models D 

through F. The standard error of the regression models through the origin is higher than the 

analogous standard regression model, suggesting weaker fit. When the y-intercept is set to zero, 

the magnitude of the coefficients changes, but the signs of the coefficients do not change, 

suggesting that the direction of the relationships between water depth and operating 

environments and costs are robust. 

All of the models in Table N.4 contain indicator variables for environmental conditions and 

the coefficients for these variables range from 140 to 201.6 suggesting that harsh-environment 

rigs are approximately $140 to $200 million more expensive than non-harsh environment rigs 

which is consistent with the summary statistics described previously. The absence of nation of 

build and drilling depth variables from the models is not surprising. The lack of a geographic 

difference is likely due to international competition which forces all shipyards to offer 

competitive pricing. Drilling depth was not a good predictor of costs because it is relatively 

invariant in the sample with most rigs capable of drilling either 30,000 or 35,000 ft wells. 

14.4.3. Semisubmersibles 

Semisubmersible newbuild cost models did not yield robust models. The best model of 

construction costs contained water depth and delivery year: 

Newbuild Cost = α0 + α1WD + α2YEAR. 

The model results are shown in Table N.5 with and without the fixed cost component. Both 

models had similar coefficients but poor predictive ability. The model suggests that for each 

1,000 foot increase in water depth capability, cost increases by $25 million, and as the year of 

delivery increases, costs increase by $38 million. Thus, a semi for delivery in 2012 should cost 

approximately $100 million more than an identical semi delivered in 2009 because of the market 

conditions which influence contract negotiations. 

For an average 8,333 ft water depth semi delivered in 2010, model B (α0=0) estimates cost at 

$535 million. Approximately 37% of the cost is associated with the water depth term and 63% is 
126

associated with the delivery year term. The influence of the delivery year on costs is time 

dependent and related to commodity prices and shipyard demand when the contracts were 

written. Hence, these terms generally do not extrapolate outside the period of analysis and are 

generally not preferred in the specification. Market conditions in the 2009-2012 period led to 

increasing price with time, however, if a different time period were selected, conditions are 

likely to be different.17 Understanding the time dimensions of cost is an important determinant of 

applying empirical relations outside their sample window. 

14.4.4. Drillships 

No combination of variables was able to capture the distinguishing features of drillship 

construction. The vast majority of drillships are under construction in Korea which eliminates the 

country of build variability inherent in the jackup and semi data sets and orders in the sample 

occurred over a short time period (2007 to mid-2008) reducing the temporal difference due to 

market conditions. Additionally, many of the vessels under build are one of three similar designs. 

In this case, the average cost of drillships adequately describes the characteristics of the sample. 

14.4.5. Design Class 

Design class was investigated as an explanatory variable for each rig class using the singlefactor model: 

Newbuild Cost = α0 + α1DESIGN. 

For semisubmersibles and drillships, design class did not improve the model results, but for 

jackups, the variable was statistically significant (Table N.6). Nine design classes were employed 

to categorize the sample data and each design class used its own indicator variable such that the 

cost is equal to the intercept plus the coefficient associated with the design class. For example, to 

determine the newbuild cost of an F&G Super M2 from Table N.6, take the intercept and add -

41.6. In cases where the p value of a parameter is not less than 0.05, the parameter cannot be said 

to differ from zero and the estimated cost is simply the intercept. 

The model predicted over 95% of the variance in costs and suggests that there is more 

variation between rig classes than within rig classes; however, the model cannot be generalized 

beyond the rig classes depicted. The Letourneau Super 116, the F&G Super M2 and the MSC 

CJ46 are priced at a discount; the KFELS ModVB, Letourneau 240C and Pacific Class 375 may 

be considered average; and the KFELS N Class, MSC CJ70 and F&G 2000A are priced at a 

premium. All three premium designs are for harsh environments. 

 

17 For example, the Sevan Brasil, will be delivered in 2012 at a cost of $685 million, but two identical rigs built 

at the same shipyard for delivery in 2014 each cost $526 million. 
127

14.5. REPLACEMENT COST MODELS

Replacement costs reflect the costs to replace a rig with a new asset of like quality and are 

related to newbuild cost. For a recently built rig, replacement cost may be estimated by reference 

to the rig’s original newbuild cost adjusted for market conditions, or the newbuild cost of similar 

rigs under construction. Replacement cost depends on technology trends, labor and material cost, 

construction supply and demand conditions, and the age of the rig at the time of the assessment. 

If new technology and improved construction methods, high competition among shipyards, and 

low demand for steel prevail in the future, replacement costs will be lower. Conversely, when 

there is high demand for shipbuilding services and a high price environment, replacement costs 

increase (Figure N.6). Since many of the factors that influence newbuild prices also impact 

replacement costs, we expect that model results will be similar. 

14.5.1. Single Variable Models 

Single variable linear regression models were created to investigate factor impacts on 

replacement costs. Water depth was a significant factor for jackups (Figure N.7) and floaters 

(Figure N.8). Delivery year was a useful descriptor for drillships (Figure N.9) but not for jackups 

and semisubmersibles due in part to the effect of upgrading which subverts the age variation. 

Drill depth was not a significant factor for any rig type. 

14.5.2. Jackups

Multivariate replacement cost models were specified using water depth (WD, ft), 

environmental indicator (HARSH), and year of delivery (YEAR, yr): 

Replacement Cost = α0 + α1WD + α2WD2

+ α3HARSH + α4YEAR. 

Model results are shown in Table N.7. Upgrade status was not a useful indicator of costs and 

was excluded. Age and water depth were significant predictors in several models, but are absent 

from the best model (model A). Water depth squared was a better predictor than water depth, 

consistent with the newbuild model relations. Costs increase with increasing water depth, harsh 

environments, and for younger rigs, as expected. Constraining the intercept to zero had little 

impact on parameter estimates. 

As in jackup newbuild models, the jackup replacement cost model included an environmental 

indicator with a coefficient of 10.6. This suggests that in the replacement cost sample, a harsh 

environment rig enjoys a premium approximately $11 million more than a non-harsh rig, much 

less than for newbuilds and likely due to the capabilities of the harsh environment rigs currently 

under build. The MSC CJ70 is capable of operating in harsh environments in water depths up to 

492 ft, and can drill wells up to 40,000 ft deep with a 7,000 ton VDL; the KFELS N Class has 

similar capabilities. These additional advanced capabilities make modern harsh environment rigs 

more expensive than those of the legacy fleet. 

Assuming an average moderate environment jackup with a water depth capability of 293 ft 

delivered in 1982, the replacement cost is estimated by model C (α0=0) to be $131 million. 

Approximately 60% of the costs are associated with the delivery year term and 40% is associated 

with the water depth term. 
128

14.5.3. Semisubmersibles 

Replacement cost models were specified using water depth (WD, ft), year of delivery 

(YEAR, yr), and environmental indicator (HARSH): 

Replacement Cost = α0 + α1WD + α2YEAR + α3HARSH. 

Model results are shown in Table N.8. All coefficients were consistent with expectations. 

The coefficient of the water depth term was 0.020 indicating that for every 1,000 foot increase in 

water depth, costs increase by $20 million. Newer rigs had higher replacement costs than older 

rigs, and each year increased cost by $2.2 million. Harsh environment rigs cost $23.8 million 

more than moderate environment rigs. For the average semi in the sample, model B (α0=0) 

estimates that 30% of costs were associated with the water depth term and 70% were associated 

with the delivery year term. 

14.5.4. Drillships 

Replacement cost models were specified using an environmental indicator (HARSH) and 

water depth (WD, ft) variables: 

Replacement Cost = α0 + α1HARSH + α2WD. 

Year of delivery was correlated with water depth and excluded from the model. Results are 

shown in Table N.9. The coefficient of the water depth term was positive and for every 1,000 ft 

increase in water depth replacement costs increased by $31 million. The harsh environment 

coefficient suggests that a harsh environment drillship costs $196 million more than a moderate 

environment drillship. This is far more than the harsh environment premium in the jackup or 

semi cost models, and is partially the result of semis and jackups being more amenable to 

modification for harsh environments. 

14.6. APPLICATION

Model application is straightforward. To determine the cost of a newbuild 350 foot water 

depth, harsh environment jack-up with a 3,000 ton variable load in 2009-2010, for example, we 

apply the results from Table N.3 and select model A since it has a low standard deviation and 

coefficients with the expected signs. To determine cost we substitute WD =350, VDL = 3000 

and HARSH = 1 into: 

Newbuild Cost = 1248 + 140*HARSH – 6.88*WD + 0.011*WD2

, 

to obtain $328 million. Confidence intervals are calculated using the standard error; a 95% 

confidence interval is given by $265 to $391 million. 
129

14.7. LIMITATIONS 

The models developed are primarily limited by the sample size of the data from which they 

are constructed, and for the replacement cost, the manner in which costs are estimated. All three 

of the newbuild cost models and the drillship replacement cost model had sample sizes under 40 

rigs. This is due to the limited drillship fleet size and the small number of rigs under construction 

at the time of analysis. 

Some of the explanatory variables may be subject to error. The models treat the 

environmental design conditions as a simple variable that can only take the form harsh or nonharsh. However, for jackup rigs, the environmental conditions which a rig can withstand depend 

in part on the water depth at that location. For example, a rig designed to operate in 350 ft in the 

Gulf of Mexico may only be able to operate in 200 feet in the North Sea. Overall, water depth 

was the single best predictor of rig cost. Water depth is believed to serve as a proxy for structural 

weight, and if weight were included the model fits may improve. 

The data provide a snapshot of market conditions as of October 2009. By fixing the time of 

assessment the effects of market fluctuations on cost data are eliminated which allows for a 

better analysis of the physical factors (water depth, harsh environment capacity, etc.) that 

influence costs. While we suspect that the factors identified as influencing costs apply to the 

market generally, the value of individual coefficients and model output will change with changes 

in shipyard supply and demand. 

It is possible to build dynamic models of rig cost, but these require a different dataset and 

model structure, and most importantly, prognostication of market conditions. By constraining the 

data to a particular point in time, problems with autocorrelation were avoided. While a timeseries analysis of newbuild or replacement costs would be valuable, the focus of this analysis 

was primarily on the physical factors that impact costs. Time-series models may be adequate 

predictors of newbuild costs, but their application requires the estimation of market conditions in 

a future period and given the volatility of the offshore oil and gas market, this may prove 

difficult. 
131

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APPENDIX A 

CHAPTER 1 TABLES AND FIGURES 
149

Table A.1. 

Environmental Criteria Used in Rig Design by Offshore Region 

North Atlantic Gulf of Mexico Asia/Pacific

100 year Wave height (ft) 46-52 52 18-45

Wind velocity (kn) 66-79 93 45-109

Surface current (kn) 1.1-2.9 3.5 3.7-3.9

1 year Wave height (ft) 42 13 16-20

Wind velocity (kn) 57 30 33

Surface current (kn) 1.7 0.8 3.5

Source: DNV, 2010

Table A.2. 

Jackup Specification Comparison for Standard and High-Spec UnitsRowan Juneau vs. Rowan EXL III 

Rowan Juneau

(standard)

Rowan EXL III

(high-spec)

Water depth (ft) 210 350

Drill depth (ft) 25,000 35,000

Year built 1977 2010

Mud pumps (number x hp) 2 x 1,600 3 x 2,200

Hook load (million lbs) 1.25 2

Variable load (million lbs) 5.5 6.5

Replacement cost (million $) 146 210

Source: Rowan, 2012; Jefferies and Company, Inc., 2012. 

Table A.3.

Advantages and Disadvantages of Station Keeping Systems 

Jack-up Anchor Spread Dynamic Positioning

Advantages Relatively simple

Not susceptible to 

power/system failures 

Low fuel costs

Simple

Not susceptible to 

power/system failures 

Capable of operating in

5,000 ft water depth

Maneuverability once in position

No anchor handling tugs are 

required

Not dependent on water depth

Short mobilization and positioning 

times

Disadvantages No maneuverability 

once positioned

Limited to water depths 

of 500 ft

Limited by seabed 

conditions

Limited maneuverability 

once anchored

Anchor handling tugs are 

required

Time to set anchors 

increases costs

Complex systems incur extra costs 

and maintenance

High fuel costs
150

Table A.4. 

Displacement and Size of Modern Semisubmersible Designs 

Design Operating 

displacement (tons)

VDL 

(tons)

Deck dimensions 

(ft x ft)

Gusto MSC DSS 20 33,500 4,400 208 x 211

Gusto MSC DSS 38 43,000 5,200 228 x 228

Gusto MSC DSS 51 58,000 8,800 254 x 256

F&G EXD 58,000 9,900 379 x 259

F&G Millennium 40,000 6,800 344 x 240

Aker H-6e 64,500 7,000 295 x 230

GVA 7500 61,000 8,200 389 x 317

Source: Industry press. 

Table A.5.

Semisubmersible Rig Generations and Technology Development 

Generation Approximate 

years of 

construction

Water depth 

(ft)

Variable 

load (tons)

Technology implementation

I 1962 - 1969 600-800 1,000-2,000 2 x 1,250 hp mud pumps, kelly, manual 

derrick

II 1970 - 1981 1,000-1,500 2,300-3,300 2 x 1,600 hp mud pumps, kelly, manual 

derrick

III 1982 - 1986 1,500-2,500 3,800-4,500 2 x 1,600 hp mud pumps, kelly, automatic 

pipe handling

IV 1987 - 1998 3,500-7,000 3,800-5,000 3 x 1,600 hp mud pumps, top drive,

automatic pipe handling, DP

V 1999 -2005 7,500-

10,000

5,000-8,000 4 x 2,200 hp mud pumps, top drive, dual 

activity, DP

VI 2005- 10,000 7,000-8,500 4-5 x 2,200 hp mud pumps, modular 

derrick drilling machine, DP3, dual 

activity

Source: PETEX, 2005; Keener et al., 2003. 

Table A.6.

Typical Semisubmersible Specifications by Generation 

Generation Design Displacement 

(tons)

Water depth 

(ft)

Drilling depth 

(ft)

Station keeping Example

I SEDCO 135 600 10,000 Moored SEDCO 135F

II Aker H-3 24,000 1,000 20,000 Moored ENSCO 5003

III Aker H-3.2 31,000 1,500 20,000 Moored Deepsea Bergen

IV GVA 4500 38,000 7,000 30,000 Moored or DP2 Transocean Rather

V F&G ExD 51,000 7,500 37,500 DP2 Development Driller II

VI Aker H-6e 71,000 10,000 33,000 DP3 Aker Barents

Source: Industry press. 
151

Table A.7. 

Specifications of Modern Drillships 

Design Displacement 

(tons)

Variable load 

(tons)

Water depth 

(ft)

Hook load (tons 

primary/auxiliary)

Mud pumps 

(number x hp)

Gusto P10000 75,000 20,000 10,000 1,250/750 4 x 2,200

Gusto PRD10000 54,000 15,000 10,000 1,000 4 x 2,200

Samsung 12000 105,000 22,000 12,000 1,250/1,000 4-6 x 2,200

Source: Industry press. 

Table A.8. 

Costs of Rigs Under Construction in 2012 in Million Dollars 

Jackups Semis Drillships

Average 217 595 634

Minimum 159 460 550

Maximum 530 809 1,150

Standard deviation 73 96 92

Sample size 77 17 47

Source: Data from Jefferies and Company, Inc., 2012. 

Table A.9. 

Replacement Costs of Selected Rigs in 2012 

Rig Class Delivery 

year

Upgrade 

year

Replacement cost 

(million $)

Deepwater Discovery Drillship 2000 615

Deepwater Navigator Drillship 1974 2000 400

Discoverer 

Inspiration

Drillship 2010 640

GSF Celtic Sea Semi 1982 1998 423

Cajun Express Semi 2000 540

Transocean 

Spitsbergen

Semi 2010 850

Constellation II Jackup 2004 210

GSF High Island Jackup 1979 150

Transocean Honor Jackup 2011 189

Source: Data from Jefferies and Company, Inc., 2012. 
152

Figure A.1. Casing diagram for a typical well. 

Source: Schlumberger, 2012.
153

Figure A.2. Horizontal, vertical, and directional well configuration. 

Figure A.3. Depth and well configuration of selected offshore wells in the U.S. GOM. 

Source: USDOE, EIA, 1993.

Source: Buvens and Gobillot, 2006.
154

Figure A.4. High temperature high pressure reservoir classification. 

Figure A.5. Global distribution of HPHT drilling in 2008. 

600 HPHT-hc

500

400 HPHT

300 Standard

200

100

Reservoir temperature (F)

10,000 20,000 30,000 40,000

Ultra-HPHT

Reservoir pressure (psi)

Source: De Bruijn et al., 2008.

Source: De Bruijn et al., 2008.
155

Figure A.6. Bottom supported versus floating rigs. 

Jackup 

<550 ft

Semisubmersible

<10,000 ft

Drillship

<12,000 ft

Source: Modified from USDOI, MMS, 2000. 
156

Figure A.7. An old submersible, a drilling barge, and a 

cantilevered jackup drilling rig. 

Source: Seadrill, 2012.

Source: Wikipedia, 2010.

Source: USDOE, NETL, 2012.
157

Figure A.8. Floating rigs. Left, the West Aquarius, a semisubmersible; right, the West Polaris drillship. 

Source: Seadrill, 2008a and 2009a. Source: Seadrill, 2008a and 2009a.
158

Figure A.9. Average wind speeds over the ocean in February (top) and July (bottom). 

Source: SWERA, 2012.
159

Figure A.10. The harsh environment Bob Palmer next to a moderate 

environment rig. 

Source: Sharples, 2009.
160

Figure A.11a. Specifications of a standard jackup (Rowan Juneau).

Source: Rowan, 2012.
161

Figure A.11b. Specifications of a high-spec jackup (Rowan EXL III).

Source: Rowan, 2012.
162

Figure A.12. Rack and pinion elevating system of a F&G Super M2 rig. 

Source: Remedial Offshore, 2011.
163

Figure A.13. Spudcan penetrating the seafloor during jackup operation. 

Figure A.14. Mat foundation. 

Seafloor

Source: Spartan Offshore Drilling, 2011.
164

Figure A.15. A cantilevered jackup rig operating at a platform. 

Source: Seadrill, 2007.
165

Figure A.16. Diagram of an NOV drill string compensator. 

Source: NOV, 2011.
166

Figure A.17. Semisubmersible generations classified according to Transocean. 

Figure A.18. The SEDCO 135-E, a 1st generation semisubmersible, built in 1967. 

1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010

3rd generation

4th generation

5th generation

6th generation

1st generation

2nd generation

Source: National Library of Australia, 1967.
167

Figure A.19. Essar Wildcat, a 2nd generation Aker H-3 

semisubmersible, built in 1977. 

Source: Offshore Energy Today.Com, 2011.
168

Figure A.20. Ocean Patriot, a 3rd generation Bingo 3000 semisubmersible, built in 1983. 

Source: Alexander, 2008.
169

Figure A.21. West Eminence, a 6th generation semisubmersible, built in 2009. 

Source: Seadrill, 2009b.
170

Figure A.22. E.W. Thornton, a drillship built in 1965. 

Source: Business Men’s Studio, 2007.
171

Figure A.23. Glomar III, a drillship built in 1966. 

Source: National Library of Australia, 1966.
172

Figure A.24. A modern drillship, the 5th generation West Navigator, built in 2000. 

Source: Seadrill, 2000.
173

Figure A.25. Dual activity derrick on the 6th generation West Polaris drillship built in 2008. 

Figure A.26. Size comparison of Discoverer Enterprise, Discoverer 534, and 

Transocean Richardson, a 4th generation semi. 

Source: Seadrill, 2008a.

Source: Cole et al., 1997.
174

Figure A.27. Transitions among rig activity states. 

Figure A.28. Four cold-stacked rigs in Sabine Pass, Louisiana. 

Maintenance

Active Ready 

stacked

Cold 

stacked

Dead 

stacked Retired

Source: Bing, 2012.
175

Figure A.29. The dead-stacked jackup rig Zeus being dismantled in Freeport, Texas.

Source: Texas General Land Office, 2008.
176

Figure A.30. Ocean Warwick grounded near Dauphin Island, Alabama, following 

Hurricane Katrina. Later rebuilt, the rig is currently operating. 

Source: SMIT Salvage, 2005.
APPENDIX B 

CHAPTER 2 TABLES AND FIGURES 
179

Table B.1. 

Distribution of Rigs by Class and Operator, Including 

Cold-Stacked Rigs and Rigs under Construction in the 1Q 2011 

Company Jackup Drillship Semi Total

Transocean Ltd. 68 23 50 141

Noble Drilling 45 13 14 72

ENSCO 49 7 20 76

Diamond Offshore 13 3 32 48

Seadrill Ltd 21 6 12 39

Hercules Offshore 53 0 0 53

COSL 27 0 6 33

Rowan 31 0 0 31

Maersk Drilling 14 0 6 20

Aban Offshore 15 3 0 18

Saipem 7 2 7 16

Nabors Offshore 16 0 0 16

Atwood Oceanics 6 1 6 13

National Drilling 13 0 0 13

ONGC 8 2 0 10

Petrobras 6 0 4 10

All others (87 firms) 147 46 66 259

Top 4 firms 205 46 116 367

Top 8 firms 337 52 134 523

Total 539 106 223 868

Source: Data from RigLogix, 2011. 
180

Table B.2. 

Geographic Distribution of Active Rigs by Nation in 2011 

Region Jackups Semis Drillships Total

US GOM 51 20 10 81

Persian Gulf 85 0 0 85

Brazil 3 52 15 70

North Sea 32 36 2 57

Southeast Asia 42 9 2 53

West Africa 17 13 9 39

India 34 2 9 45

China 28 4 0 32

Mexico 24 3 0 27

Egypt 20 2 2 24

Australia 1 7 1 9

Ghana 0 3 2 5

Azerbaijan 2 3 0 5

Venezuela 3 0 2 5

All others 49 20 8 77

Top 4 171 108 27 306

Top 8 292 136 47 475

Total 394 175 57 626

Source: Data from Rigzone, 2011. 
181

Table B.3. 

Contract Drilling Service Market Size in 2010 

Jackups

(million $)

Floaters

(million $)

Total

(million $)

Persian Gulf 3,253 3,253

Southeast Asia 1,931 2,092 4,023

North Sea 1,865 6,436 8,302

India 1,263 1,369 2,632

Mexico GOM 1,075 256 1,331

West Africa 994 4,314 5,307

US GOM 983 3,781 4,765

Red Sea 511 511

Mediterranean 509 1,291 1,799

China 1,377 526 1,903

Venezuela & Caribbean 296 292 588

Brazil 72 7,615 7,688

Australia 57 1,022 1,079

Total 14,187 28,588 42,775

Source: Data from Rigzone, 2011; Authors calculations. 

Table B.4. 

E&P Firm Investment in Contract Drilling 

Services by Region in 2010 

Region INTSOK 

estimate

(billion $)

Author’s 

estimate

(billion $)

Brazil 9.2 7.7

Asia 8.5 8.5

North America 8.6 6.1

West Africa 8.8 5.3

North Africa and Mideast 5.2 5.5

Russia and FSU 1.8

Australia 3.3 1.0

North Sea 3.4* 8.3

Total 48.8 42.7

Note (*): Does not include Norway 

Source: Rystad Energy, 2011.
182

Table B.5. 

Number of Newbuild Rigs on Order by Shipyard in 2011 

Shipyard Drillship Jackup Semisub 

Daewoo 11 3 

Samsung 16 2 

Keppel FELS 1 17 4 

Jurong* 5 3 

PPL* 6 

Dalian 4 

ABG 4 

Hyundai 6 

Lamprell 4 

COSCO 1 3 

Note: (*) Part of Sembcorp Marine. 

Source: Data from RigLogix, 2011.

Table B.6. 

Worldwide Distribution of MODU Construction in 2011 

Country Drillship Semi Jackup Capital expenditures 

(million $) 

Percentage 

(%) 

South Korea 38 5 0 27,125 47.8 

Singapore 2 7 33 13,402 23.6 

China 3 6 9 6,979 12.3 

Brazil 7 0 2 5,088 9.0 

UAE 0 1 6 1,585 2.8 

India 0 0 5 1,048 1.8 

Vietnam 0 0 1 180 0.3 

US 0 0 2 375 0.7 

Russian 

Federation 

0 0 1 100 0.2 

Malaysia 0 0 1 227 0.4 

Norway 0 1 0 614 1.1 

Total 50 20 60 56,723 

Source: Data from RigLogix, 2011; Authors calculations. 
183

Table B.7. 

Number of Rigs Upgraded in 2009 and 2010 by Shipyard 

Shipyard Nation 2009 2010

Aker Norway 1

Keppel Singapore 2 2

Keppel Netherlands 1 2

Hindustan India 1

Keppel Philippines 1

Lamprel UAE 3 8

L&T Oman 1

Keppel Brazil 3

Sembawang Singapore 1

Others 3

TOTAL 13 16

Source: Offshore Magazine, 2009 and 2010. 
184

Table B.8. 

Examples of Jackup Rig Upgrade Contracts 

Customer Shipyard Year Cost 

(million $)

Scope

ENSCO Lamprell 2008 14.8 Steel renewal, leg repairs, 

accommodation upgrade, piping 

renewal, painting

Aban Offshore ABG 2011 13.2 Painting, steel renewal, 

replacement of equipment

Gulf Drilling KeppelQatar2011 16.2 Major upgrade

National Drilling Drydocks 

World

2010 20 Life extension

Millennium

Offshore

Lamprell 2011 27.5 Conversion to accommodation 

unit

GSP Lamprell 2010 12 Upgrade electrical, drilling 

equipment, accommodation 

refurbishment

Japan Drilling Lamprell 2010 11.8 Three month refurbishment

Source: Industry press. 
185

Table B.9.

Examples of Semisubmersible Rig Upgrade Contracts 

Customer Shipyard Year Cost 

(million $)

Scope

Transocean Semco 2011 20 Piping installation

Diamond Offshore Keppel AmFELS 2012 300 Complete rebuild

Noble Signal 2010 15 Addition of helideck, 

quarters upgrade, structural 

modifications

Awilco Remontowa 2010 75 Increase variable load, new 

accommodations, power 

supply

Diamond Keppel 2008 310 Complete rebuild

Fred Olsen 2010 160 Survey, renewal and 

upgrade

Awilco Remontowa 2010 15 Survey

Source: Industry press. 
186

Table B.10. 

Examples of Drillship Upgrade Contracts 

Customer Shipyard Year Cost 

(million $)

Scope

Transocean Signal 2010 32.4 Living quarters upgrade, 

equipment replacement, 

painting, hull and tank repair

Noble Keppel Brazil 2010 152 Replacement of 

accommodations and heliport; 

modifications to stern

Neptune Marine Sembawang 2009 340 Increase water depth capacity, 

add dynamic positioning, 

upgrade drilling equipment

Source: Industry press. 

Table B.11. 

Number of Major Upgrades by Year and Estimated 

Market Value, 2001-2010 

Jackups Floaters Total Market value 

($ billion)

2001 8 7 15 0.6-1.9

2002 32 10 42 1.0-3.3

2003 15 12 27 1.0-3.3

2004 22 15 37 1.3-4.3

2005 9 9 0.1-0.2

2006 13 20 33 1.6-5.3

2007 36 29 65 2.5-8.1

2008 18 18 36 1.5-4.9

2009 9 4 13 0.4-1.2

2010 11 5 16 0.5-1.5

Total 172 115 287 10.1-34.3

Source: Offshore Magazine, 2001-2010. 
187

Table B.12. 

Number of Transactions in the Secondhand 

Market by Firm, 2005-2010 

Firm Buyer Seller 

Hercules 7 4 

Seadrill 8 3 

Transocean 10 

Songa 4 4 

Noble 6 

ENSCO 1 4 

Rowan 3 2 

Diamond 1 4 

Maersk 2 3 

Aban 3 1 

Saipem 4 

Source: Data from RigLogix, 2011. 

Table B.13. 

Average and Range of Prices in the Secondhand 

Market, 2005-2010 

Year Jackups 

($ million) 

Floaters 

($ million) 

2005 42 (22–60)a37 (13–60) 

2006 67 (17–210) 102 (14–270) 

2007 148 (26–212) 321 (211–675) 

2008 106 (9–200) 294 (5–676) 

2009 84 (5–199) 475 (460–490) 

2010 188 (26–356) 288 (102–560) 

Source: RigLogix, 2011. 

Note: (a) Price range shown in parentheses.
188

Table B.14. 

Transactions and Market Valuation in the Secondhand Market, 2005-2010 

Year Jackups Drillships Semis Total Market value 

($ billion)

2005 9 1 5 15 0.5

2006 20 1 10 31 2.1

2007 13 3 6 22 3.7

2008 10 1 3 14 2.2

2009 10 0 3 13 2.0

2010 20 7 4 31 6.8

Total 82 13 31 126 17.3

Source: Data from RigLogix, 2011; Authors Calculations. 
189 

Figure B.1. Direction of cash flow through offshore rig markets. 

Contract 

drilling

market

E&P firms

Newbuild 

market

Scrap market

Secondhand 

market

Upgrade 

market
190 

Figure B.2. Six month moving average of regional jackup and floater dayrates, 2000-2011. 

0

50,000

100,000

150,000

200,000

250,000

300,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Dayrate ($/day)

GOM

North Sea

Persian Gulf

West Africa

Southeast Asia

Jackups

0

100,000

200,000

300,000

400,000

500,000

600,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Dayrate ($/day)

West Africa

Southeast Asia

North Sea

GOM

Floaters

Source: Data from RigLogix, 2011.
191 

Figure B.3. Number of wells drilled per year, 1994-2010. 

Figure B.4. Geographic distribution of the number of offshore wells drilled in 2011. 

Source: Douglas-Westwood, 2009.

Source: Hureau et al, 2011.
192 

Figure B.5. Annual revenue of the offshore contract drilling market, 2000–2012. 

Source: Modified from GBI Research, 2010.
193 

Figure B.6. Average cost of jackup and floater deliveries by water depth, 2000–2013. 

0

50

100

150

200

250

300

350

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Price (million $)

Less than 350 ft

Greater than 350 ft

Jackups

0

100

200

300

400

500

600

700

800

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Price (million $)

Semis

Drillships

Floaters

Source: Data from RigLogix, 2011.
194 

Figure B.7. Deliveries of newbuild rigs by class, 1974–2014. 

0

10

20

30

40

50

60

70

80

Pre

1974

1977 1980 1983 1986 1989 1992 1995 1998 2001 2004 2007 2010

Number Delivered

Jackups

Floaters

0

5

10

15

20

25

30

35

40

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Number delivered

Jackup

Semisub

Drillship

Source: Data from RigLogix, 2011.

E E E
195 

Figure B.8. Newbuild market size, 2000–2012. 

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Market size (million $)

Jackups

Floaters

Source: Data from RigLogix, 2011.
APPENDIX C 

CHAPTER 3 TABLES AND FIGURES 
199 

Table C.1. 

Distribution of Active Rigs by Nation in 2011 

Country Jackups Semis Drillships Total Region

US 51 20 10 81 US GOM

Brazil 3 52 15 70 Brazil

India 34 2 9 45 India

China 28 4 0 32 China

Norway 7 22 1 30 North Sea

UK 12 14 1 27 North Sea

Mexico 24 3 0 27 Mexican GOM

Egypt 20 2 2 24 Red Sea/Mediterranean

UAE 24 0 0 24 Persian Gulf

Saudi Arabia 23 0 0 23 Persian Gulf

Iran 20 1 0 21 Persian Gulf

Qatar 20 0 0 20 Persian Gulf

Malaysia 12 6 1 19 Southeast Asia

Nigeria 9 4 4 17 West Africa

Angola 4 7 5 16 West Africa

Vietnam 13 2 0 15 Southeast Asia

Indonesia 11 1 1 13 Southeast Asia

Singapore 2 6 3 11 Southeast Asia

Australia 1 7 1 9 Australia

Netherlands 8 0 0 8 North Sea

Gabon 4 2 0 6 West Africa

Thailand 6 0 0 6 Southeast Asia

Ghana 0 3 2 5 West Africa

Azerbaijan 2 3 0 5 Caspian Sea

Denmark 5 0 0 5 North Sea

Venezuela 3 0 2 5 Caribbean 

All others 45 14 5 64

Total 394 175 57 626

Source: RigLogix, 2011.
200 

Table C.2. 

Major Features of Offshore Regions 

Region 2010 

Production

(million 

BOE/day)

Features

West 

Africaa

3.9 Nations vary in maturity with Nigeria well developed and Cameroon and 

Ghana frontier regions. Nearly all production is from Nigeria and Angola; 

growth is in the deepwater market, especially in Angola, but the shallow 

water market accounts for most production. IOCs are major E&P players.

China 1.0 CNOOC and subsidiary COSL are the major players. Major development 

began in the 1980’s and 1990’s and investment has increased from $3.4 

billion in 2005 to $12.5 billion in 2011. Offshore activity accounts for 20% 

of national production.

India 1.1 Growing market with a strong gas sector. Offshore accounts for two-thirds 

of national production. The NOC ONGC and public firm Reliance are 

major E&P players.

Southeast 

Asiab

3.1 Strong shallow and deepwater segments. Subject to typhoons. Rig count 

has approximately doubled since 1990. Offshore production accounts for 

half of production in Indonesia and over 90% of production in Malaysia. 

North 

Seac

6.1 Mature region with harsh and moderate conditions. There has been a 

modest decline in rig count since 2000. Statoil and IOCs are major E&P 

players.

Persian 

Gulfd

6.7 NOCs are primary players. Between 1990 and 2010 rig count increased 

fourfold from approximately 20 to 80.

Mexico 

GOM

2.5 Primarily a shallow water market with little deepwater activity. Developed 

rapidly in the early 1990’s and again in the early 2000’s. Offshore 

production in decline. Deepwater exploration slated for 2011.

US GOM 2.7 Mature offshore region. Shallow water region in decline; deepwater market 

growing. Accounted for 15% of total oil production in 2011. Periodically 

severely impacted by hurricanes.

Brazil 2.1 Large deepwater market with little shallow water activity. Offshore 

accounts for 90% of national production. Growth in production due to presalt discoveries. Petrobras is the NOC and major E&P player. 

Source: Rystad Energy, 2011.

Note: (a) Composed of Nigeria, Angola, Cameroon, Ghana, Gabon, and Equatorial Guinea. 

(b) Composed primarily of Indonesia (33% of production) and Malaysia (65% of production); Vietnam and 

the Philippines are emerging markets. 

(c) Dominated by UK and Norway with minor activity in the Netherlands, Germany and Denmark. 

(d) Includes Saudi Arabia, Kuwait, Qatar, UAE, Bahrain and Iran. 
201 

Table C.3. 

Average Water Depth of Rig Contracts, 2000–2010 

Jackups (ft) Floaters (ft)

Average Standard 

deviation

Min Max Average Standard 

deviation

Min Max

West Africa 125 84 17 397 3,372 1,888 118 9,325

China 85 42 20 300 1,112 1,599 75 6,709

India 187 80 9 352 3,270 2,694 135 9,678

Southeast 

Asia

170 71 15 531 2,006 2,041 55 7,732

North Sea 165 77 24 426 786 718 87 5,354

Persian Gulf 113 65 8 307

Mexico GOM 138 66 32 305 1,096 1,341 145 5,741

US GOM 106 79 6 485 3,540 2,288 30 10,139

Brazil 3,437 1,930 30 9,370

World 119 82 6 531 2,674 2,195 30 10,139

Source: Data from RigLogix, 2011.
202 

Table C.4. 

Active and Ready-Stacked Rigs by Market in 2011

Jackups (ft) Floaters (ft)

Environment <300 >300 <7,500 >7,500

North Sea Moderate 10 6 15 2

Harsh 0 20 17 4

Persian Gulf Moderate 43 52 0 0

Harsh 0 3 0 0

West Africa Moderate 6 13 12 10

Harsh 1 2 4 4

India Moderate 6 28 6 5

Harsh 0 0 0 0

US GOM Moderate 33 17 8 22

Harsh 0 2 0 1

Brazil Moderate 4 3 40 13

Harsh 0 0 6 5

China Moderate 17 12 3 0

Harsh 0 0 0 1

Southeast Asia Moderate 2 48 16 6

Harsh 0 0 2 1

Mexico Moderate 9 14 1 1

Harsh 0 1 0 1

All others Moderate 20 26 14 10

Harsh 1 5 7 3

Total Moderate 150 219 115 69

Harsh 2 33 36 20

Source: RigLogix 2011. 

Table C.5. 

Relationships between the Number of Active and Contracted Rigs, 

1999–2011 

Region Correlation 

coefficient

Average proportion (%) of 

contracted rigs that are active

US GOM 0.95 82

Southeast Asia 0.65 75

Africa -0.27 44

Persian Gulf 0.43 40

North Sea 0.49 71

Source: Data from RigLogix, 2011; Baker Hughes 2012.
203 

Table C.6. 

Average Utilization Rates by Region, 2000–2010

Jackups (%) Floaters (%)

2000–

2006 

2006–

2010 

2000–

2010 

2000–

2006 

2006–

2010 

2000–

2010 

West Africa 84 81 83 82 90 86

Southeast Asia 86 81 84 57 50 54

North Sea 89 91 90 73 91 82

Persian Gulf 85 82 84

US GOM 74 55 65 69 82 76

Source: Data from RigLogix, 2011.

Table C.7. 

Jackup Utilization Regional Correlation Matrix, 2000–2010 

US GOM West Africa Southeast Asia North Sea Persian Gulf

US GOM 1

West Africa 0.50 1

Southeast Asia 0.55 0.84 1

North Sea 0.37 0.70 0.71 1

Persian Gulf 0.33 0.73 0.83 0.56 1

Average 0.44 0.70 0.73 0.59 0.61

Source: Data from RigLogix, 2011.

Table C.8. 

Floater Utilization Regional Correlation Matrix, 2000–2010 

US GOM West Africa Southeast Asia North Sea Brazil

US GOM 1

West Africa 0.62 1

Southeast Asia -0.14 0.15 1

North Sea 0.82 0.66 -0.14 1

Brazil 0.68 0.39 -0.05 0.82 1

Average 0.50 0.46 -0.05 0.54 0.46

Source: Data from RigLogix, 2011. 
204 

Table C.9. 

Average Dayrates by Region between 2000–2006 and 2006–2010 

Jackups Floaters

2000–

2006 

($/day)

2006–

2010 

($/day)

Change 2000–

2006 

($/day)

2006–

2010 

($/day)

Change

West Africa 69,379 154,488 123% 163,534 374,130 129%

Southeast Asia 67,846 159,731 135% 92,229 278,060 201%

North Sea 86,927 180,657 108% 113,330 337,589 198%

Persian Gulf 58,126 106,541 83%

US GOM 48,776 81,865 68% 122,530 361,995 195%

Source: Data from RigLogix 2011. 

Table C.10. 

Jackup Dayrate Regional Correlation Matrix, 2000–2010 

US GOM North Sea Persian Gulf West Africa Southeast Asia

US GOM 1

North Sea 0.49 1

Persian Gulf 0.51 0.64 1

West Africa 0.54 0.73 0.72 1

Southeast Asia 0.58 0.78 0.77 0.90 1

Average 0.53 0.66 0.66 0.72 0.76

Source: Data from RigLogix, 2011. 

Table C.11. 

Floater Dayrate Regional Correlation Matrix, 2000–2010 

US GOM North Sea West Africa Southeast Asia

US GOM 1

North Sea 0.88 1

West Africa 0.84 0.87 1

Southeast Asia 0.77 0.79 0.77 1

Average 0.83 0.85 0.83 0.78

Source: Data from RigLogix, 2011. 
205 

Table C.12. 

Quarterly Volatility in the Shallow and Deepwater 

Markets, 2000–2010 

Shallow (%) Deepwater (%)

West Africa 15.7 28.7

Southeast Asia 12.6 37.5

US GOM 15.0 17.2

North Sea 18.3 18.2

Persian Gulf 23.4

Average 17.0 25.4

Source: Data from RigLogix, 2011. 

Note: Volatility is defined as the standard deviation of the 

percent change in dayrates between quarters.

Table C.13. 

Contract Type by Rig Market and Region, 2000–2010 

Shallow water Deepwater

Fixed well (%) Term (%) Fixed well (%) Term (%)

West Africa 39 61 38 62

Southeast Asia 40 60 64 36

US GOM 76 24 45 55

Persian Gulf 22 78

North Sea 47 53 40 60

World 52 48 43 57

Source: Data from RigLogix, 2011. 

Table C.14. 

Average Contract Duration in Days, 2000–2010 

West 

Africa

Persian 

Gulf

Southeast 

Asia

North Sea US GOM All regions

Jackups 260 511 248 190 77 148

Floaters 261 213 233 173 212

Source: Data from RigLogix, 2011. 
206 

Table C.15. 

Largest E&P Customers by Region, 2000–2010 

Region First Second Third Fourth Top 

four

Jackups US GOM Chevron (8) Apache (6) BP (4) ADTI (3) 21

North Sea Maersk (18) Shell (9) Conoco (9) BP (6) 43

Southeast 

Asia

Petronas (12) Shell (11) Total (7) Chevron (6) 37

Persian Gulf Saudi Aramco 

(22)

ADMA (9) Rasgas (6) Maersk (5) 43

West Africa Chevron (29) Exxon (18) Total (11) Addax (6) 65

Floaters US GOM BP (16) Shell (10) Anadarko (9) Chevron (6) 40

North Sea Statoil (30) Shell (11) Norsk Hydro 

(10)

BP (7) 58

Southeast 

Asia

Shell (18) Petronas 

(12)

Exxon (8) Murphy (8) 46

West Africa Total (23) Exxon (16) Chevron (10) Shell (5) 55

Note: Market share as a percent of total contracted days in parenthesis. 
207 

Figure C.1. Illustration of the method used for averaging dayrates. 

Duration of contract

B

C

A

Jan Feb Mar

Average dayrates

Jan=(A+B)/2

Feb=NA

Mar=C
208 

Figure C.2. Global supply of newbuild and existing MODUs in the 1Q 2012. 

MODUs

868

Floaters

329

Drillships

106

Semis

223

Jackups

539

Harsh 

45

>300

293

<300

201

Source: Data from RigLogix, 2011.
209 

Figure C.3. Global supply of MODUs in the 1Q 2012. 

Source: Data from RigLogix, 2011.
210

Figure C.4. Offshore drilling regions and 1Q 2011 drilling activity. 

Source: Data from RigLogix, 2011.
211 

Figure C.5. Number of active rigs by region, 1987–2012.

North Sea US GOM

Southeast 

World 

Persian Gu

Source: Data from Baker Hughes, 2012. 
212

Figure C.6. National distribution of active rigs within regions, 1987–2012. 

North Sea Persian Gulf

West Africa Southeast Asia

Source: Data from Baker Hughes, 2012.

Number of active rigs
213 

Figure C.7. Relationship between the number of contracted jackups and the 

number of active rigs in the U.S. GOM by month, 1999–2011. 

Source: Data from RigLogix, 2011; Baker Hughes, 2012.
214 

Figure C.8. Number of contracted jackups by region, 1999–2012. 

US GOM

North Sea

West Africa

Persian Gulf

World Southeast Asia Source: Data from RigLogix, 2011. 
215 

Figure C.9. Number of contracted floaters by region, 1999–2012. 

West Africa

Southeast Asia 

US GOM

North Sea

World

Source: Data from RigLogix, 2011. 
216 

Figure C.10. Six month moving average of world utilization rates, 2000–2011. 

Source: Data from RigLogix, 2011.
217 

Figure C.11. Six month moving average of jackup utilization rates in selected regions, 

2000–2011. 

Source: Data from RigLogix, 2011.
218 

Figure C.12. Six month moving average of floater utilization rates in selected regions, 2000–2011. 

Figure C.13. Illustration of the movement of rigs in response to high utilization rates. 

Region A

Region B

Initial conditions 

1 active rigs

2 total rigs

= 5 %

Utilization:

18 active rigs

2 total rigs

= 9 %

Utilization:

Rig movement Final conditions 

1 active rigs

15 total rigs

= 67%

Utilization: 

18 active rigs

25 total rigs

= 72%

Utilization: 

5 inactive rigs

 move to 

Region B 

Source: Data from RigLogix, 2011.

USGOM
219 

Figure C.14. Relationship between utilization rate and the increase in market capacity in the 

Persian Gulf and Southeast Asia, 2000–2011. 

Source: Data from RigLogix, 2011.
220 

Figure C.15. Relationship between utilization rate and rig movement in the North Sea, 2000–2011. 

Source: Data from RigLogix, 2011.
221 

Figure C.16. Six month moving average of jackup and floater dayrates, 2000–2011. 

Source: Data from RigLogix, 2011.

US GOM

US GOM
222 

Figure C.17. Quarterly change in average dayrates in selected regions, 2000–2011. 

Source: Data from RigLogix, 2011.

Jackup

s

Floater

s
APPENDIX D 

CHAPTER 4 TABLES AND FIGURES 
225 

Table D.1. 

The Largest Publicly Traded Drilling Contractors in 2011 

Firm Enterprise 

valuea

(billion $)

Fleet valuea

(billion $)

2011 

revenue 

(billion $)

Jackups Semis Drillships Total Headquarters

Transocean 25.4 32.1 9.1 68 50 23 141 U.S.

Seadrill 27.1 15.6 4.0 21 12 6 39 Norway

Diamond Offshore 8.9 8.7 3.3 13 32 3 48 U.S.

ENSCO 16.7 14.5 2.8 42 18 5 65 U.S.

Noble 13.3 11.7 2.7 45 14 13 72 U.S.

Saipem 26c4.5 1.0b7 7 2 16 Italy

Rowan 4.5 5.7 0.9 31 0 0 31 U.S.

Songa Offshore 1.7 1.9 0.7 0 5 0 5 Norway

Ocean Rig 3.6 3.0 0.7 0 2 4 6 Norway

Atwood Oceanics 3.2 2.7 0.6 6 6 1 13 U.S.

Aban 2.9 2.4 0.6 15 0 3 18 India

Hercules Offshore 1.3 1.1 0.5b33 0 0 33 U.S.

Vantage 1.5 1.7 0.3 4 0 4 8 U.S.

Japan Drilling 0.4 1.2 0.3 4 2 0 6 Japan

Total 110.5 106.8 26.4 289 148 64 501

% of world fleet 54% 66% 60% 58%

Note: (a) Enterprise and fleet value evaluated on December 21, 2011. (b) Only includes offshore drilling 

revenues. (c) Most of Saipem’s enterprise value is associated with non-offshore drilling activities and is 

not included in the total. 

Source: Jefferies and Company, Inc., 2012; financial reports; RigLogix, 2011.
226 

Table D.2.

The Largest State-Owned Drilling Contractors in 2011 

Firm Nation/Market Jackups Semis Drillships Total Publically 

traded

China Oilfield Services Ltd. China 27 6 0 33 Yes

National Drilling UAE 13 0 0 13 No

ONGC India 8 0 2 10 Yes

Petrobras Brazil 6 4 0 10 Yes

Socar Azerbaijan 6 3 0 9 No

Egyptian Drilling Egypt 7 0 0 7 No

Gulf Drilling International Qatar 6 0 0 6 No

CNPC China 4 0 0 4 Yes

Gazflot Russia 2 2 0 4 No

NIDC Iran 4 0 0 4 No

Arabian Drilling Saudi Arabia 4 0 0 4 No

PV Drilling Vietnam 4 0 0 4 No

Sheng Li China 4 0 0 4 No

VietSovPetro Vietnam 3 0 0 3 No

Caspian Drilling Azerbaijan 0 2 0 2 No

Saudi Aramco Saudia Arabia 2 0 0 2 No

ArcticMorNefteGazRazvedka Russia 2 0 0 2 No

Petrobaltic Poland 2 0 0 2 Yes

PDVSA Venezuela 2 0 0 2 No

KNOC Korea 0 1 0 1 No

Pemex Mexico 1 0 0 1 Yes

Total 107 18 2 127

% of world fleet 20% 8% 2% 15%

Source: RigLogix, 2011. 
227 

Table D.3.

Selected Privately Held Drilling Contractors in 2011 

Firm Market Jackups Semis Drillships Total

Maersk Drillinga North Sea 14 6 0 20

Stena Drilling North Sea 0 4 4 8

Dolphin A/Sb North Sea 0 7 1 8

Schahin Brazil 1 2 4 7

Odfjell North Sea 0 4 2 6

Queiroz Galvao Brazil 0 6 0 6

Odebrecht Brazil 0 2 3 5

Perforadora Central Mexico 5 0 0 5

GSP Black Sea 5 0 0 5

Jagson India 4 0 0 4

Spartan Offshore GOM 4 0 0 4

SeaWolf Africa 3 0 0 3

Subtotal 36 31 14 81

All others 107 36 31 174

Total 143 67 45 255

% of world fleet 27% 30% 42% 29%

Note: (a) Subsidiary of A.P. Moller-Maersk; (b) Subsidiary of Fred Olsen Energy 

Source: RigLogix, 2011.

Table D.4. 

Enterprise Value of Selected Drilling Contractors as a 

Percent of Fleet Value, 2010–2012 

Firm 1Q 2012

(% of NAV)

1Q 2011

(% of NAV)

1Q 2010

(% of NAV)

Transocean 62 117 133

Seadrill 225 245 266

Diamond 93 128 131

ENSCO 116 104 83

Noble 104 126 106

Rowan 75 89 60

Atwood 111 126 112

Hercules 132 132 129

Vantage 59 92 80

Source: Jefferies and Company, Inc., 2009, 2011, and 2012. 
228 

Table D.5. 

Specializations and Business Strategies of Selected Firms in 2011

Firm Specialization % of 2011 revenues 

from floater fleet

Business strategies

Diamond Semis and 

jackups

93 Operates an old but upgraded fleet; 

frequently pays investor dividends 

rather than newbuilding but is entering 

high-spec drillship market.

ENSCO Generalist 60 Formerly operated a jackup-focused 

fleet, but acquired Pride in 2011, 

adding floaters and diversifying fleet.

Hercules Low spec 

jackups

0 Buys inexpensive secondhand rigs; 

does not typically participate in 

newbuilding; focused on U.S. GOM 

and Persian Gulf.

Noble Generalist 60 Seeks to operate a diverse fleet in a 

number of regional markets.

Rowan Jackups 0 Traditional jackup operator moving into 

deepwater market; operates primarily in 

high-spec shallow water markets.

Seadrill High-spec 64 Operates only high spec rigs; active in 

newbuilding and maintains aggressive 

growth strategy; focuses on Southeast

Asia, North Sea. 

Songa Semis 100 Operates small fleet of semis with 

emphasis on the North Sea.

Transocean Generalist 85 Active in all major regions and water 

depths, but focused on deepwater.

Atwood Semis 83 Operates a small but relatively diverse 

fleet; primarily focused on Southeast 

Asia.

Source: Financial reports. 
229

Table D.6. 

Four Largest Firms by Number of Active Rigs per Region and Water Depth Category in 2011 

Water depth 

(ft)

West Africa Southeast Asia North Sea Persian Gulf US GOM

<250 Noble Drilling 2 Hercules Offshore 1 ENSCO 5 National Drilling 11 Hercules Offshore 19

Hercules Offshore 1 Schlumberger 1 Noble Drilling 4 Nabors Offshore 5 Nabors Offshore 5

KCA Deutag 1 Swift Drilling BV 1 ENSCO 4 ENSCO 3

SeaWolf Oil Services 1 Noble Drilling 4

250–550 Transocean 6 Seadrill 11 Maersk Drilling 8 Rowan 10 Rowan 8

Noble Drilling 2 Transocean 8 Rowan 5 Noble Drilling 9 ENSCO 5

SeaWolf Oil Services 2 ENSCO 8 Transocean 4 Transocean 5 Noble Drilling 3

Pride International 1 Vantage Energy Services 3 Noble Drilling 4 Aban Offshore 5 Hercules Offshore 1

<3,000 Transocean 3 Transocean 2 Transocean 12 Diamond Offshore 1

Noble Drilling 1 Japan Drilling 2 Dolphin A/S 4 Larsen O&G 1

Saipem 1 Maersk Drilling 2 Diamond Offshore 3

Diamond Offshore 1 Songa Offshore AS 2

3,000–7,500 Transocean 6 Transocean 3 North Atlantic Drilling 2 Transocean 4

Diamond Offshore 1 Diamond Offshore 1 Transocean 1 Noble Drilling 3

Noble Drilling 1 Noble Drilling 1 Saipem 1 Diamond Offshore 1

Saipem 1 Atwood Oceanics 1 Dolphin A/S 1

>7,500 Transocean 2 Transocean 2 Aker Drilling A/S 2 Transocean 8

ENSCO 2 Seadrill 1 Odfjell 1 ENSCO 6

Seadrill 2 Saipem 1 Stena Drilling 1 Noble Drilling 3

Ocean Rig Asa 2 ENSCO 1 North Atlantic Drilling 1

Source: Data from RigLogix, 2011. 
230

Table D.7. 

Drilling Contractor Revenues in Million U.S. Dollars by Region in 2011 

Diamond ENSCO Hercules Noble Rowan Seadrill Transocean

Brazil 1,641 583 572 710 1,000

US GOM 323 753 302 524 264 185 1,900

UK 152 240 164 230 150 1,200

Norway 74 1,392

Angola 318 250 182

Mexico 62 148 16 402 28

Saudi Arabia 93 96 204 69

Nigeria 98 204

China 230

Qatar 132 60

India 61 102

Other 826 866 85 703 79 918 4,900

Note: Blank values do not indicate that the contractor received no revenue from the region; only that the 

revenue was not considered significant enough to list separately 

Source: Financial reports. 

Table D.8. 

Major E&P Customers of Selected Drilling Contractors in 2011 

E&P Customers (% of revenues)

Drilling 

Contractor

First Second Third Fourth

Atwood Chevron (30%) Shell (21%) Kosmos 

(21%)

Diamond Petrobras (35%) OGX (14%)

ENSCO Petrobras (16%)

Hercules Chevron (25%) Saudi Aramco 

(13%)

ONGC (9%) PEMEX (3%)

Noble Shell (24%) Petrobras (18%) Pemex (15%)

Rowan Saudi Aramco (29%) McMorRan (21%) Total (11%)

Seadrill Petrobras (17%) Statoil (15%) Total (10%) Shell (9%)

Transocean BP (10%)

Source: Financial reports.
231

Table D.9. 

Transocean and Diamond Performance Statistics by Market Segment in 2011

Firm Rig class Operating 

costs*

(1,000 $/day)

Dayrate

(1,000 $/day)

Net revenue 

(1,000 $/day)

Utilization 

(%)

Expected net 

revenue

(1,000 $/year)

Transocean Ultra-deepwater 199 533 334 79 81,056

Deepwater 135 349 214 44 6,774

Harsh floaters 171 450 279 95 93,623

Mid-water floaters 91 280 189 69 37,303

High-spec jackups 81 114 33 71 -22

Jackups 29 96.5 67.5 49 6,674

Diamond Ultra-deepwater 169 342 173 82 40,676

Deepwater 119 416 297 94 99,295

Mid-water floaters 86 269 183 72 39,303

Jackups 36 82 46 47 927

Note: (*) Includes active and inactive costs 

Source: Financial reports.
232

Table D.10. 

Market Concentration Metrics of the World MODU 

Fleet in 2010 

Jackup Semisub Drillship Floaters

CR4 (%) 53 68 69 54

CR8 (%) 79 85 88 67

HHI 940 1,628 2,511 1,692

Source: Data from RigLogix, 2011. 
233

Figure D.1. Contracted days in global offshore drilling market by company ownership, 

2000–2010. 

0

100

200

300

400

2000 2002 2004 2006 2008 2010

Contracted days (1000 days)

Public Private State-Owned

Jackups

0

50

100

150

200

250

300

2000 2002 2004 2006 2008 2010

Contracted days (1000 days)

Public Private State-Owned

Floaters

Source: Data from RigLogix, 2011.
234

Figure D.2. Relationship between enterprise value and revenue and earnings for selected drilling 

contractors on December 31, 2011. 

Transocean

Seadrill

Diamond

ENSCO

Noble

Rowan

Vantage Songa

Aban & Atwood

y = 3.0715x + 2.8412

R2 = 0.7136

0

5

10

15

20

25

30

35

0 1 2 3 4 5 6 7 8 9 10

Enterprise value (billion $)

2011 revenue (billion $)

Atwood

Diamond

ENSCO

Vantage & 

Hercules

Noble

Rowan

Transocean

Seadrill

Songa

y = 8.668x + 0.4475

R2 = 0.8878

0

5

10

15

20

25

30

0 0.5 1 1.5 2 2.5 3 3.5

Enterprise value (billion $)

2011 earnings (billion $)

Source: Data from Jefferies and Company, Inc., 2012.
235

Figure D.3. Relationship between fleet size and fleet value for selected drilling contractors on 

December 31, 2011.

Figure D.4. Relationship between enterprise value and fleet value for selected drilling 

contractors on December 31, 2011.

Transocean

Seadrill

Diamond

ENSCO

Noble

Saipem Rowan

Atwood

Aban

Hercules

Vantage, Japan 

Drilling, Ocean Rig 

& Songa

y = 0.2164x - 0.1151

R2 = 0.8798

0

5

10

15

20

25

30

35

0 20 40 60 80 100 120 140 160

Fleet value (billion $)

Fleet size (# of rigs)

Source: Data from Jefferies and Company, Inc., 2012.

Source: Data from Jefferies and Company, Inc., 2012.
236

Figure D.5. Debt to market capitalization of Seadrill and Songa, 2008–2011. 

Figure D.6. Average fleet age and the proportion of the fleet stacked in December 2010. 

Source: Data from Jefferies and Company, Inc., 2012.

Source: Data from Jefferies and Company, Inc., 2012.
237

Figure D.7. Delivery year and average dayrates of jackups and floaters from 2000–2010. 

Source: Data from RigLogix, 2011.
238

Figure D.8. Inventories of jackup and floater fleets for selected firms in 2011. 

0

10

20

30

40

50

60

70

Atwood Diamond ENSCO Hercules Noble Rowan Seadrill Songa TransoceanVantage

Number of rigs

Standard jackups

High-spec jackups

0

10

20

30

40

50

60

70

80

Atwood Diamond ENSCO Hercules Noble Rowan Seadrill Songa Transocean Vantage

Number of rigs

Standard floaters

High-spec floaters

Source: Financial reports.
239

Figure D.9. Relationship between firm size and relative newbuilding expenditure, 2005–2011. 

Source: Data from Jefferies and Company, Inc., 2012.
240

Figure D.10. Selected mergers among major players in the offshore drilling market, 1990–2010. 

Pre 1990 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010

The Offshore Company Transocean

Transocean

Ross Offshore

Wilrig ASA

Forex

Sedco

Cliffs Drilling

R&B

Arcade Drilling

Falcon

Global Marine

Sante Fe

Aker

Noble Noble

Transworld Drilling

The Western Company

Chiles Offshore

Neddrill Holding

ENSCO ENSCO

Penrod

Dual Drilling

Chiles Offshore

Pride

Forasol Foramer

Marine Drilling

Diamond Offshore Diamond 

Odeco Drilling

Arethusa

Zapata Offshore

Source: Modified from Lee and Jablonowski, 2010.
241

Figure D.11. Consolidation in the offshore contract drilling industry, 1984–2010. 

Source: Feyling, 2004; RigLogix, 2011.
242 

Figure D.12. Herfindahl-Hirschman Index of jackup and floater regional markets, 2001–2010. 

Source: Data from RigLogix, 2011. 

US GOM 

US GOM 
APPENDIX E 

CHAPTER 5 TABLES AND FIGURES 
245 

Table E.1. 

Offshore Drilling Contracts by Region, 2000–2010

Jackup Drillship Semisub Total

West Africa 314 114 243 671

Southeast Asia 465 25 149 639

North Sea 600 14 615 1,229

Persian Gulf 341 0 2 343

US GOM 3,441 91 709 4,241

Total 5,161 244 1,718 7,123

Source: Data from RigLogix, 2011.

Table E.2. 

Average Dayrates by Region between 2000-2006 and 2006–2010 

Jackups Floaters

2000–2006 

($/day)

2006–2010 

($/day)

Change 2000–2006 

($/day)

2006–2010 

($/day)

Change

West Africa 69,379 154,488 123% 163,534 374,130 129%

Southeast Asia 67,846 159,731 135% 92,229 278,060 201%

North Sea 86,927 180,657 108% 113,330 337,589 198%

Persian Gulf 58,126 106,541 83%

US Gulf of Mexico 48,776 81,865 68% 122,530 361,995 195%

Source: Data from RigLogix, 2011.
246 

Table E.3. 

Models of the Relationship between Utilization Rates and Dayrates, 2006–2010 

ln(DRt) = β0+ β1 lnUx

β0 β1

Region x=12 x=18 x=24 R

2 Autoregressive order

Jackups West Africa 12.2 1.2 0.62 none

Southeast Asia 12.3 1.7 0.80 none

North Sea 12.2 3.0 0.27 none

Persian Gulf 12.2 3.9 0.35 none

US GOM 11.7 1.0 0.77 first

World 12.0 1.5 0.67 none

Floaters West Africa 12.8 3.0 0.98 first

Southeast Asia NA

North Sea 12.8 2.4 0.99 second

US GOM 13.3 3.5 0.99 second

World 13.4 3.9 0.99 second

Source: Data from RigLogix, 2011.

Table E.4. 

Relationship between Maximum Drilling Depth and Dayrates, 2000–2010 

Drilling depth 

category (ft)

Dayrate

($/day)

Number in 

sample

Standard error

($/day)

Significantly 

different

Jackups Less than 15,000 53,804 41 4,299 A

15,000 to 20,000 58,421 1,866 786 A

20,000 to 25,000 86,580 1,632 1,257 B

25,000 to 30,000 98,508 975 1,919 C

Greater than 30,000 170,375 100 7,707 D

Floaters Less than 20,000 168,664 117 10,794 A

20,000 to 25,000 176,570 1,099 3,885 A

25,000 to 30,000 255,213 407 7,324 B

30,000 to 35,000 264,882 212 9,020 B

Greater than 35,000 409,058 35 23,104 C

Source: Data from RigLogix, 2011.
247 

Table E.5. 

Relationship between Maximum Water Depth and Dayrates, 2000–2010 

Water depth 

category (ft)

Dayrate

($/day)

Number in 

sample

Standard error

($/day)

Significantly 

different

Jackups Less than 200 51,916 1,045 860 A

200 to 250 69,241 1,520 1,089 B

250 to 300 81,192 1,245 1,374 C

300 to 350 88,616 726 2,005 D

350 to 400 118,920 517 3,129 E

Greater than 400 112,378 108 5,389 E

Floaters Less than 2,500 170,227 856 4,361 A

2,500 to 5,000 193,760 426 6,515 B

5,000 to 7,500 227,887 320 7,333 C

Greater than 7,500 309,754 360 7,615 D

Source: Data from RigLogix, 2011.

Table E.6. 

Rig Specifications and Average Dayrates, 2000–2010 

Station keeping

Average dayrate

($/day)

Number 

in sample

Standard error

($/day)

Jackups Independent leg cantilever 87,746 3,480 940

Mat or slot 53,125 1,134 820

Floaters DP 295,775 408 6,923

Moored 182,891 1,458 3,443

Source: Data from RigLogix, 2011.
248 

Table E.7. 

Effects of Rig Specification on Dayrates by Region, 2000–2010 

Station keeping Water depth Drilling depth

Region Mat or slot IC <300 ft >300 ft <25,000 ft >25,000 ft

Jackups US GOM 52,820 67,334* 53,035 72,342* 55,473 78,692*

Persian Gulf 72,192 88,758 77,617 98,785* 80,155 149,148*

West Africa 63,401 106,436* 92,554 113,135* 101,833 151,267*

North Sea 56,227 125,691 108,099 135,411* 108,011 153,195*

Southeast Asia 98,415 112,842 123,181 113,566 100,624 148,617*

Moored DP <5,000 ft >5,000 ft <25,000 ft >25,000 ft

Floaters US GOM 164,102 295,672* 109,536 249,683* 132,681 252,088*

West Africa 225,577 295,959* 225,852 279,454* 226,167 300,893*

North Sea 193,719 293,500* 199,186 302,776* 196,592 309,149*

Southeast Asia 173,393 311,534* 157,737 236,094* 159,480 267,475*

Note: (*) Indicates significant difference (p<0.05). 

Source: Data from RigLogix, 2011.

Table E.8. 

Premium Associated with High Specification Rigs, 2000–2010 

Premium ($/day)

Region Station 

keeping

Water depth Drilling depth

Jackups US GOM 14,514 19,307 23,219

Persian Gulf 21,168 68,993

West Africa 43,035 20,581 49,434

North Sea 27,312 45,184

Southeast Asia 47,993

Floaters US GOM 131,570 140,147 119,407

West Africa 70,382 53,602 74,726

North Sea 99,781 103,590 112,557

Southeast Asia 138,141 78,357 107,995

Note: Computed as the difference in row categories in Table E.7. Blank values 

indicate non-significant results. 
249 

Table E.9. 

Influence of Contract Duration on Dayrates in the Jackup and Floater Markets, 2000-2010 

Region Average 

contract length 

(days) 

Long-term 

dayrate 

($/day) 

Short-term 

dayrate 

($/day) 

Premium 

($/day, %) 

Jackups West Africa 260 111,273 85,986 25,287 (29) 

Southeast Asia 248 111,619 98,831 12,788 (13) 

North Sea 190 126,263 100,086 26,177 (26) 

Persian Gulf 511 100,421 69,345 31,076 (45) 

US GOM 77 59,385 48,465 10,920 (23) 

Floaters West Africa 261 297,852 237,797 60,055 (25) 

Southeast Asia 213 238,702 167,538 71,164 (42) 

North Sea 233 257,595 192,843 64,752 (34) 

US GOM 

173 295,625 159,880 

135,745 

(85) 

Note: Long-term and short-term contracts are defined relative to the regional mean duration. Premium is 

the difference between long and short-term contracts as a percentage of long-term dayrate. 

Source: Data from RigLogix, 2011.

Table E.10. 

Average Dayrates by E&P Firm Classification, 2000–2010 

 E&P firm Average dayrate 

($/day) 

Number in 

sample 

Jackups NOC 114,608A261 

 IOC 88,588B 1,008 

 Independent 71,788C 3,893 

Floaters NOC 274,776A200 

 IOC 226,757B610 

 Independent 189,832C 1,145 

Note: Letters indicate significant differences at p=0.05. 

Source: Data from RigLogix, 2011.
250 

Table E.11. 

Models of the Relationship between Dayrates and E&P Firm Ownership, 2000–2010 

 = 

Coefficient Variable Jackup model Floater model

 

Intercept -14,940,018 -67,703,588

 

IND -16,914 -30,484

 

IOC -10,962 -4,631NS

 YEAR 7,512 33,859

 GOM -37,064 6,1427

 N.SEA 16,058 49,386

 AFRICA -2,579NS 84,499

 PGULF -29,575

Note: NS indicates the term is not significant. 

Source: Data from RigLogix, 2011.

Table E.12. 

Average Floater Dayrates by Well Type, 2000–2010 

Appraisal 

($/day)

Development 

($/day)

Exploratory 

($/day)

Water depth Midwater (< 3,000 ft) 271,624A202,623B237,740AB

Deepwater (3,000-7,500 ft) 430,455A325,031B291,286C

Ultra-deepwater (>7,500 ft) 438,750A403,759AB 357,191B

Region West Africa 433,974A366,197A338,087A

Southeast Asia 328,742A217,513A258,469A

North Sea 344,632A240,501B307,938A

U.S. GOM 378,404A331,684A258,624B

All floaters 362,727A286,758B289,567B

Note: Letters indicate significant differences at p=0.05. 

Source: Data from RigLogix, 2011.
251 

Figure E.1. Illustration of the method used for averaging dayrates. 

Figure E.2. Global active rig count and oil prices, 2001–2011. 

Duration of contract

B

C

A

Jan Feb Mar

Average dayrates

Jan=(A+B)/2

Feb=NA

Mar=C

Source: Data from RigLogix, 2011.
252 

Figure E.3. Relationship between jackup and floater dayrates and oil prices, 2000–2010. 

Source: Data from RigLogix, 2011.
253 

Figure E.4. Dayrates and utilization rate in the U.S. GOM jackup market. 

Source: Data from RigLogix, 2011.
254 

Figure E.5. Model relationship between utilization rates and dayrates in three jackup markets, 2006–

2010.

Figure E.6. Model relationship between utilization rates and dayrates in three floater markets, 2006–2010. 

Source: Data from RigLogix, 2011.

Source: Data from RigLogix, 2011
APPENDIX F 

CHAPTER 6 TABLES AND FIGURES 
257 

Table F.1. 

NPV Newbuild Model Variable Definitions 

Variable Unit Description

C $ Purchase price of the rig

T yr Maturity of debt

I %/yr Interest rate of debt

G % of C Upgrade cost

Oa $/day Daily operating costs when the rig is active

Os $/day Daily operating costs when the rig is stacked

DR $/day Dayrate

t yr Life time of the rig

Ut % Utilization rate in year t

Ue % Average utilization rate over t

X %/yr Tax rate

D %/yr Discount rate
258 

Table F.2. 

Optimistic and Expected Parameterizations of the 

Newbuilding Model

Variable Unit Expected Optimistic

C $ million 200 175

T yr 7 15

I %/yr 4.5 3

G % of C 25 25

Oa $/day 60,000 50,000

Os $/day 10,000 6,000

DR $/day Variable Variable

t yr 25 25

Ut % Variable Variable

Ue % Variable Variable

X %/yr 15 10

D %/yr 15 10
259 

Table F.3. 

Stacked and Active Operating Expenditures for Jackups and Floaters, 2010–2011 

Rig type Firm Rig type Status OPEX ($/day) 

Jackups Transocean High-spec Operating 87,000 

 Stacked 10,600 

 Standard Operating 46,000 

 Stacked 6,900 

 Hercules Domestic Operating 32,000 

 Stacked 6,700 

 International Operating 47,000 

 Stacked 8,000–12,000 

 Diamond High-spec Operating 55,000 

 Standard Operating 45,000–

Floaters Transocean Ultra-deepwater Operating 150,000 58,000

 Deepwater Operating 137,000 

 Stacked 26,000 

 Midwater Operating 104,000 

 Stacked 10,000 

Source: Firm annual reports. 

Table F.4. 

Percentage Effects of a 1% Change in Selected Variables on the Break-Even Dayrate 

Model OPEX 

(Oa) 

Interest rate 

(I) 

Purchase price 

(C) 

Tax rate 

(X) 

Fixed utilization 0.50% 0.12% 0.50% 0.04% 

Variable utilization 

Ue = 0.05 0.26% 0.15% 0.65% 0.16% 

Ue = 1 0.50% 0.12% 0.50% 0.04% 
260 

Table F.5. 

Stacking Model Variable Definitions 

Variable Units Description

Oa $/day Daily operating costs when the rig is active

Os $/day Daily operating costs when the rig is stacked

DR $/day Dayrate

Ue % Average utilization rate 

y days Time rig is to be stacked

F $ Fixed reactivation costs

R $/day Variable reactivation costs

Table F.6. 

Net Asset Values of Rig Classes, 4Q 2011 

Class Water depth 

(ft)

Environment Built NAV 

(million $)

Jackup 400 Moderate Modern 210

Jackup 375 Moderate Modern 203

Jackup 350 Moderate Modern 195

Jackup 300 Moderate Modern 180

Jackup 400 Harsh Modern 230

Jackup 375 Harsh Modern 223

Jackup 350 Harsh Modern 215

Jackup 300 Harsh Modern 200

Jackup 350 Moderate 1980’s 70

Jackup 300 Moderate 1980’s 50

Jackup 350 Harsh 1980’s 105

Jackup 300 Harsh 1980’s 80

Semi Second generation 170

Semi Third generation 210

Semi Fourth generation 300

Semi Fifth generation 530

Semi Sixth generation 570

Drillship 1970’s 110

Drillship 4,000 205

Drillship 8,000 540

Drillship 10,000 590

Source: Morgan Stanley, 2011. 
261 

Table F.7. 

Parameterization of the NAV Model

Variable Unit Description Value

C $ Net asset value NAV

Oa $/day Operating costs 60,000

DR $/day Dayrate Variable

t yr Remaining life of the rig 25-A

Ue % Utilization Variable

X %/yr Tax rate 15

D %/yr Discount rate 15

A yr Age of the rig 5, 10 or 20

Table F.8. 

Comparison of NAV Estimates for Two Standard 300 ft Jackup Rigs in January 2012 

Rig Age Dayrate 

($/day)

Utilization rate 

(%)

Discount rate 

(%)

Authors 

NAV 

(million $)

Jefferies 

NAV 

(million $)

Galaxy II 14 167,000 90 15 166 170

Galaxy III 13 144,000 90 15 131 156

Source: Jefferies and Company, Inc., 2012. 
262 

Figure F.1. Diagram of the variable utilization model and stacking decision. 

Figure F.2. Utilization rate over the rig lifecycle in the variable utilization model. 

Ue

 t = e .5 sin t 

Ut

if Ut > 30%

if Ut < 30%

Operate; 

OPEXt = 

Oa*365

Stack; 

OPEXt = 

Os*365
263 

Figure F.3. NPV break-even points of utilization and dayrates under expected and optimistic 

assumptions for fixed utilization. 

Figure F.4. NPV break-even points of utilization and dayrates with fixed and variable utilization 

rates under the expected scenario. 

Expected scenario
264 

Figure F.5. The impacts of an initial two year contract on break-even dayrates and utilization rates. 

Figure F.6. Sensitivity of the break-even dayrate fixed utilization model to changes in discount rate. 
265 

Figure F.7. Effect of utilization on the benefit of the stacking versus operating. 

Figure F.8. Effect of stacking duration on the benefit of stacking versus operating. 
266 

Figure F.9. Sample net asset values of Seadrill floaters as calculated by Jefferies, 4Q 2011. 

Figure F.10. Net asset value over time for two similar rigs, November 2008–

November 2011. 

Source: Jefferies and Company, Inc., 2011.

Source: Jefferies and Company, Inc., 2011.
267 

Figure F.11. Relationship between NAV and dayrates and utilization rates for rigs of different ages. 
APPENDIX G 

CHAPTER 7 TABLES AND FIGURES 
271 

Table G.1. 

Worldwide Distribution of Rig Construction in 2012 

Country Jackups Semis Drillships

Singapore 40 4

China 18 6 3

Mexico 1 4

UAE 8

Brazil 2 1 7

India 5

Vietnam 2

Korea 37

Italy 1

Russia 1

Total 77 16 47

Source: Data from Jefferies and Company, Inc., 2012. 

Table G.2. 

Shipyard Deliveries from 2005-2012 and 2011 Market Capitalization 

Shipyard Nation Jackups Semis Drillship 2011 market 

capitalization 

(billion $)

Keppel Singapore 38 10 2 15.1

Sembcorp Singapore 33 10 8.8

Daewoo Korea 6 12 7.6

CIMC Raffles China 3 6

Samsung Korea 4 24 9.5

IMAC UAE 4

COSCO/Dalian China 12 4 3.1

Aker Norway 2

Severodvinsk Russia 1 1

LeTourneau U.S. 8

AmFELS U.S. 12

Lamprell UAE 12 0.5

ABG India 4 0.3

CNOOC China 4

Others 13 3 4
272 

Table G.3. 

Jackup Construction in U.S. Shipyards, 2000–2012

Name Shipyard Delivery 

date

Design Drilling 

depth (ft)

Harsh Water 

depth (ft)

Rowan Gorilla VI Vicksburg, MS 2000 LeTourneau Super Gorilla 219-C 35,000 Yes 400

Rowan Gorilla VII Vicksburg, MS 2001 LeTourneau Super Gorilla 219-C 35,000 Yes 400

Seawork 1 New Iberia, LA 2002 Liftboat No 140

ENSCO 105 Brownsville, TX 2002 KFELS B Class 30,000 No 375

Bob Palmer Vicksburg, MS 2003 LeTourneau Super Gorilla XL 224-C 35,000 Yes 550

Tonala Brownsville, TX 2004 KFELS B Class 25,000 No 375

Scooter Yeargain Vicksburg, MS 2004 LeTourneau Tarzan Class 225-C 35,000 No 300

Bob Keller Vicksburg, MS 2005 LeTourneau Tarzan Class 225-C 35,000 No 300

Hank Boswell Vicksburg, MS 2006 LeTourneau Tarzan Class 225-C 35,000 No 300

Offshore Courageous Brownsville, TX 2007 LeTourneau Super 116 30,000 No 350

Panuco Vicksburg, MS 2007 LeTourneau Super 116E 25,000 No 350

Offshore Defender Brownsville, TX 2007 LeTourneau Super 116 30,000 No 350

Offshore Resolute Brownsville, TX 2008 LeTourneau Super 116 30,000 No 350

Ocean Scepter Brownsville, TX 2008 KFELS B Class 35,000 No 350

Offshore Vigilant Brownsville, TX 2008 LeTourneau Super 116 30,000 No 350

Rowan Mississippi Vicksburg, MS 2008 LeTourneau Workhorse 240C 35,000 No 375

JP Bussell Vicksburg, MS 2008 LeTourneau Tarzan Class 225-C 35,000 No 300

Atwood Aurora Brownsville, TX 2008 LeTourneau Super 116E 30,000 No 350

Offshore Intrepid Brownsville, TX 2009 LeTourneau Super 116 30,000 No 350

Ralph Coffman Vicksburg, MS 2009 LeTourneau Workhorse 240C 35,000 No 400

Tuxpan Brownsville, TX 2010 LeTourneau Super 116E 30,000 No 375

Rowan EXL I Brownsville, TX 2010 LeTourneau Super 116E 40,000 No 350

Rowan EXL II Brownsville, TX 2010 LeTourneau Super 116E 35,000 No 350

Rowan EXL III Brownsville, TX 2010 LeTourneau Super 116E 40,000 No 350

Joe Douglas Vicksburg, MS 2011 LeTourneau Workhorse 240C 35,000 No 350

Rowan EXL IV Brownsville, TX 2012 LeTourneau Super 116E 40,000 No 350

Source: Data from RigLogix, 2011. 
273 

Table G.4. 

Deliveries of Semisubmersibles from U.S. Shipyards, 2000–2012 

Name Water 

depth (ft)

Nominal cost 

(million $)

Delivery 

year

Shipyard

ENSCO 7500 8,000 225 2000 TDI- Halter, Orange, TX

Ocean Confidence 10,000 510 2001 TDI- Halter, Sabine, TX

Leiv Eiriksson 8,200 440 2001 Friede Goldman Halter, 

Pascagoula, Mississippi

Erik Raude 10,000 555 2002 Friede Goldman Halter, 

Pascagoula, Mississippi

Q4000 1,000 156 2002 AmFELS

Source: Colton, 2011; Industry press. 

Table G.5. 

Number of Newbuild (2005-2012) Rigs in the Fleets of 

Selected Drilling Contractors in 2012 

Firm Jackups Semis Drillships Total

Seadrill 20 10 6 36

Transocean 4 5 11 20

COSL 15 5 20

ENSCO 7 7 5 19

Noble 8 8 16

Rowan 13 3 16

Maersk 8 3 4 15

Diamond 1 4 4 9

Aban 9 9

Vantage 4 5 9

Atwood 4 2 2 8

National Drilling 5 5

Songa 4 4

Stena 4 4

Source: Data from RigLogix, 2011. 
274 

Figure G.1. Jackup rig construction by region, 1950–2012. 

Figure G.2. Jackup rig construction in Asian countries, 1970–2012. 

Source: Data from RigLogix, 2011; Colton, 2011.

Source: Data from RigLogix, 2011; Colton, 2011.
275 

Figure G.3. Oil price and worldwide delivery rates of jackup rigs and floating rigs, 1974–2012. 

0

20

40

60

80

100

120

0

10

20

30

40

50

60

70

80

Pre 1974 1979 1984 1989 1994 1999 2004 2009

Inflated oil price ($/bbl)

Number delivered

Jackup deliveries

Oil price

0

20

40

60

80

100

120

0

5

10

15

20

25

30

 Pre 1974 1979 1984 1989 1994 1999 2004 2009

Inflated oil price ($/bbl)

Number delivered

Floater deliveries

Oil price

Source: Data from RigLogix, 2011.
276 

Figure G.4. Relationship between the two-year lagged oil price and number of jackups delivered, 

1975–2012. 

Source: Data from Riglogix, 2011.
277 

Figure G.5. Relationship between the two-year lagged average dayrate and number of jackups delivered, 

2000–2012. 

Source: Data from RigLogix, 2011.
278 

Figure G.6. Layout of the Keppel FELS shipyard in Singapore and satellite view in 2011. 

Source: Keppel FELS, 2011; Google Earth, 2011.
279 

Figure G.7. Sembcorp’s Jurong and PPL shipyards in 2012. 

Source: Sembcorp Marine, 2012a and 2012b.
280 

Figure G.8. The LeTourneau Vicksburg, Mississippi shipyard. 

Figure G.9. The AmFELS Brownsville, Texas shipyard. 

Source: Pictometry Bird’s Eye, 2011.

Source: Keppel Corp., 2011.
APPENDIX H 

CHAPTER 8 TABLES AND FIGURES 
283 

Table H.1. 

Number of Rigs Delivered and Under Construction Worldwide by Design Class, 1Q 2012 

Rig Class Number under build 

(1Q 2012)

Number delivered 

(2000–2011)

Harsh design

F&G Super M2 5 11

MSC CJ70 3 3 Y

MSC CJ46 2 8

MSC CJ50 4

F&G 2000E/2000A 15 11 Y

CPLEC CP 300 2

LeTourneau Super 116E 12 20

LeTourneau 240 C 2 3

LeTourneau Super Gorilla 3

LeTourneau Tarzan 4

PPL Pacific 375/400 3 28

KFELS B/Super B Class 19 30

KFELS Super A Class 6 2 Y

KFELS N Class 3 Y

F&G 3000N 6 Y

F&G L780 5

Unknown/other 2 5

Total 77 140

Source: Data from RigLogix, 2011. 

Table H.2. 

Characteristics of Selected Gusto MSC Jackups 

CJ46 CJ50 CJ70

Hull dimensions (ft) 203 x 213 223 x 

230

292 x 

Leg length (ft) 483 480 319 672

Water depth (ft) 350 350 492

Elevated weight (tons) 13,640 18,700 33,000

Source: Gusto MSC, 2010. 
284 

Table H.3. 

Jackup Rigs Delivered from U.S. Yards between 2000–2012 

Design Number delivered

LeTourneau Super 116/Super 116E 14

LeTourneau Super Gorilla 3

LeTourneau 240 C 3

LeTourneau Tarzan 4

KFELS B Class 2

Source: Data from RigLogix, 2011. 

Table H.4. 

Characteristics of Commonly Built Jackup Rigs 

Design Length 

(ft)

Width 

(ft)

Leg length 

(ft)

Variable load 

(tons)

Drilling 

depth (ft)

LeTourneau Tarzan 215 196 445 3,850 35,000

LeTourneau Super 116E 243 206 477 3,650 30,000

LeTourneau 240C 228 220 491 4,850 35,000

LeTourneau Super Gorilla 

XL

306 300 713 5,950 35,000

KFELS Super B Class 246 218 486 5,600 35,000

Gusto MSC CJ70 290 319 672 8,000 40,000

F&G 2000E 231 250 547 6,500 35,000

Pacific Class 375 236 224 506 3,750 30,000

Source: Rig specification sheets. 
285 

Figure H.1. Jackup rig design is analogous to ship design spiral. 

Source: Eyers, 2007.
286 

Figure H.2. Four common rig designs; clockwise from upper left: BMC Pacific 375; KFELS N class; 

LeTourneau 240 C; LeTourneau Super 116E. 

Source: Seadrill, 2008a; Rowan, 2012.
287 

Figure H.3. Main deck (left) and machinery deck (right) layout of a LeTourneau Super 116E. 

243 ft

Source: LeTourneau, 2011.
288 

Figure H.4. Early jackup rig Sea Gem in 1964. 

Figure H.5. Size comparison of the Gusto MSC CJ70 class rig. 

Source: Bugge., 2011.

Source: Kellezi et al., 2008.
289 

Figure H.6. Cylindrical and trussed legs on the Bethlehem MS-225 Spartan 202 and 

Gusto MSC CJ70 Maersk Inspirer. 

Source: Spartan Offshore Drilling, 2011; Maersk Drilling, 2011.
290 

 

Figure H.7. Alternative leg and chord designs. 

Source: Hamada et al., 1982; Vazquez et al., 2005.

Half round

Brace

Rack

Back plate

Rack

Brace

Half Round Chords

Teardrop Chords

Triangular leg

Square leg
291 

Figure H.8. Rack chocks are inserted against the leg’s racks to transfer the vertical load away from the 

pinions. 

Source: Remedial Offshore, 2011.
292 

Figure H.9. Mat foundation of a jackup rig. 

Source: Young et al., 1981.
293 

Figure H.10. Cantilever drilling rig operating over a fixed platform. 

Source: JDC, 2008.
294 

Figure H.11. Common U.S. built jackup designs; clockwise from top left: LeTourneau Super 116E, 

LeTourneau Tarzan, LeTourneau 240C, LeTourneau Super Gorilla XL. 

Source: Seadrill, 2012; Hsieh, 2010; Offshore Magazine, 2003.
295 

Figure H.12. Hull dimensions of common LeTourneau jackup designs. 

Source: Ralls, 2009.
296 

Figure H.13. LeTourneau Super Gorilla XL size comparison. 

LeTourneau 

Super Gorilla XL

Source: Offshore Shipping Online, 2000.
297 

Figure H.14. Commonly built international jackups; clockwise from upper left: KFELS B Class, Gusto 

MSC CJ70, Pacific Class 375, F&G JU 2000E. 

Source: Seadrill, 2012; Friede and Goldman, 2012.
APPENDIX I 

CHAPTER 9 FIGURES 
301 

Figure I.1. Work processes in jackup assembly. 
302 

Figure I.2. Early construction stages of jackup rigs: F&G JU 2000E (top) and Hank Boswell

(bottom) at the LeTourneau Vicksburg, Mississippi yard. 

Friede and Goldman, LTD., 2008.
303 

Figure I.3. Structural design of a jackup hull. 

Source: Rammohan, 2005.
304 

Figure I.4. Hull construction of a F&G Super M2 rig (top) and two LeTourneau Super 116s at 

the AmFELS Brownsville, Texas yard. 

Source: Remedial Offshore, 2011.
305

Figure I.5. Topside installation on F&G JU 2000E (left) and Bob Palmer (right) at the LeTourneau Vicksburg, Mississippi yard. 

Friede and Goldman, LTD., 2008.
306 

Figure I.6. Principal components of leg chords. 

Figure I.7. Formed half chords pressed by Jackrabbit Steel. 

Source: Jackrabbit Steel Products, Inc., 2011.

Rack Assembled chord Half round

Source: ArcelorMittal, 2012.
307 

Figure I.8. Launching rigs at AmFELS (top) and LeTourneau (bottom) shipyards. 

Source: Keppel Corp., 2011; Pitts, 2005.
308 

Figure I.9. Construction of F&G Super M2; top section of leg installed. 

Source: Remedial Offshore, 2011.
APPENDIX J 

CHAPTER 10 FIGURES 
311 

Figure J.1. Example specification sheet for Seadrill’s KFELS B Class jackup. 

Source: Seadrill, 2008b.
312

Figure J.2. Interactions between major rig systems. 

Drilling Systems

Well

Pipe Handling Systems

Mud Systems

Safety/BOP Systems
313

1. Crown Block and Water Table

2. Catline Boom and Hoist Line

3. Drilling Line

4. Monkeyboard

5. Traveling Block

6. Top Drive

7. Mast

8. Drill Pipe

9. Doghouse

10. Blowout Preventer

11. Water Tank

12. Electric Cable Tray

13. Engine Generator Sets

14. Fuel Tanks

15. Electric Control House

16. Mud Pump

17. Bulk Mud Components Storage

18. Mud Pits

19. Reserve Pits

20. Mud Gas Separator

21. Shale Shaker

22. Choke Manifold

23. Pipe Ramp

24. Pipe Racks

25. Accumulator

Figure J.3. Drilling rig system components. 

Source: OSHA, 2012.
314

Figure J.4. A derrick and cantilever on a jackup rig. 

Source: Bugge, 2011.
315

Figure J.5. Top drive system. 

Source: Bugge, 2011.
316

Figure J.6. Drawworks. 

Source: Bugge, 2011.
317

Figure J.7. Drilling fluid circulation diagram. 

Source: Baars et al., 2001.
318

Figure J.8. Lewco mud pump. 

Source: LeTourneau, 2010.
319

Figure J.9. Shale shaker (top) and hydrocyclone (bottom). 

Source: GN Solids Control, 2011; NOV. 2011.
320

Figure J.10. BOP stack on a jackup rig including four ram BOPs and one 

annular BOP. 

Source: Bugge, 2011.
321

Figure J.11. Schematic of a ram BOP. 

Blind ram blocks

Pipe ram blocks

Shear ram blocks

Source: Wikipedia, 2011.
322

Figure J.12. Iron roughneck. 

Source: Bugge, 2011.
323

Figure J.13. Catwalk machine. 

Source: Bugge, 2011.
324

Figure J.14. Pipe deck machine. 

Source: Bugge, 2011.
325

Figure J.15. Drilling control stations.

Source: Bugge, 2011.
APPENDIX K 

CHAPTER 11 TABLES AND FIGURES 
329 

Table K.1. 

Leg Weights of Alternative Rig Designs 

Source Rig type Environmental 

design

Leg mass 

(tons)

Leg length 

(ft)

Leg density 

(tons/ft)

Massie and Liu, 1990 Generic Moderate 1,400 508 3

Cassidy et al., 2004 Generic Harsh 3,141 558 6

Pers. Comm. Confidential Moderate 971 482 2

William et al., 1999 Generic Harsh 2,123 377 6

PetroProd, 2009; Yang et al., 2002 CJ70 Harsh 2,255 672 3

Global Chimaks, 2009 F&G L780 Moderate 585 338 2
330

Table K.2. 

Jackup Rig Lightship Displacements 

Rig Name Design Weight

(tons)

Water Depth 

(ft)

Severe? Build 

Year

Length 

(ft)

Width 

(ft)

Ensco 97* LeTourneau 82 SDC 5,559 250 No 1980 207 176

Ensco 96* Hitachi 250 C 5,969 250 No 1982 193 174

Ensco 94* Hitachi 250 C 6,417 250 No 1981 193 174

Ensco 88* LeTourneau 82 SDC 6,745 250 No 1982 207 176

Ensco 53* F&G L780 Mod II 7,172 300 No 1982 180 175

Diamond M Nugget Levingston 111 7,263 300 No 1976 208 178

Ensco 54* F&G L780 Mod II 7,747 300 No 1982 180 175

Amarnath* F&G L780 Mod II 7,749 300 No 1982 180 175

DYVI Beta CFEM 8,030 350 No 1978 230 212

Ensco 95* Hitachi 250 C 8,443 250 No 1982 193 174

Generic CJ 40 8,525 300 No 2010 193 180

Sagadrill2 Mitsubishi T76J 8,720 300 No 1981 194 184

Sagadrill1 Mitsubishi T76J 9,228 300 No 1984 194 184

Soraya 9,350 225 No 1970 177 133

Vicksburg* LeTourneau 84S 9,625 300 No 1976 238 213

Ensco 92* LeTourneau 116 C 9,711 250 No 1982 243 200

Ensco 87* LeTourneau 116 C 9,751 350 No 1982 243 200

Offshore Resolute LeTourneau Super 116 10,605 350 No 2008 243 206

Offshore Courageous LeTourneau Super 116 10,682 350 No 2008 243 206

Offshore Vigilant LeTourneau Super 116 10,698 350 No 2008 243 206

Offshore Freedom LeTourneau Super 116E 11,274 350 No 2009 243 206

Energy Exerter* CFEM 2005 11,364 300 Yes 1982 245 283

Energy Enhancer* CFEM 2005 11,368 300 Yes 1982 245 283

Generic Generic 12,200 330 No 1990 255 295

Generic CJ 46 x 100 12,210 375 No 2010 214 203

Murmanskay CDB Corall 14,800 330 No 1991 357 252

Arcticheskaya CDB Corall 15,200 330 Yes 2011 357 252

Glomar Moray Firth CFEM T2600C 15,334 300 Yes 1984 324 284

Hakuryu 10 BMC 375 17,500 375 No 2008 236 224

Generic CJ 50 x 120 17,600 400 No 2010 230 223

Generic CJ 70 x 150 28,600 450 Yes 2010 291 318

Note: (*) Estimated as transit displacement minus transit variable load. 

Source: Industry press; rig specification sheets.
331

Figure K.1. The Hitachi 250, LeTourneau Super 116E, and Gusto MSC CJ70 rigs. 

Water Depth (ft)

Source: Seadrill, 2012; Lewis, 2011; Maersk, 2005. Weight (tons)
332

Figure K.2. Distribution of rigs in the sample. 
333

Figure K.3. Relationship between water depth and rig weight. 

y = 70.26x - 10932

R2 = 0.5679

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

200 250 300 350 400 450 500

Lightship displacement (tons)

Water depth (ft)

Moderate Environment

Harsh Environment

y = 0.1119x - 224.15

R2 = 0.6338

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

0 50,000 100,000 150,000 200,000 250,000

Lightship displacment (tons)

Water depth squared (ft2)

Moderate Environment

Harsh Environment
334

Figure K.4. Relationship between hull dimensions and rig weight. 
335

Figure K.5. Model relationship between water depth and predicted weight for rigs of different 

length and breadth. 
APPENDIX L 

CHAPTER 12 TABLES AND FIGURES 
339

Table L.1.

Market Share (in Percent) of Rig Equipment Suppliers in U.S. Jackup Rig Construction, 2000–2010 

Supplier Engines BOP Topdrive Rotary Mudpumps Derrick Manufacturing 

locations

Caterpillar 95 Indiana, Georgia

Wartsilla 5 Europe

Woolslayer 33 Oklahoma

Loadmaster 33 Louisiana

NOV 17 50 50 15 34 Texas

Cameron 66 Louisiana

Hydril 15 Texas

Lewco 50 50 85 Texas

Source: RigLogix, 2011. 

Table L.2. 

Rig Construction Cost Estimation Modules 

Module Sub-module User input Model assumptions Adjustment factor

Labor Capital costs Productivity, hourly 

wages 

Shipyard earnings 

index

Material Steel Lightship 

weight

Weight distribution, 

steel price

Steel mill 

products index

Generators/engines Installed 

power

Price per kW Machinery and 

equipment index

Other material Capital costs Fixed percentage All finished 

goods 

Rig kit Fixed price Ship and boat 

building index

Drilling 

equipment

Fixed price Oil field 

equipment index

Returns on 

investment

Capital costs Fixed percentage
340

Table L.3. 

Construction Costs of U.S. Jackup Rigs, 1996–2011 

Rig Construction cost 

(million $)

Order 

year

Inflated cost 

(2010 million $)

Rowan Gorilla VI 208 1996 305

Rowan Gorilla VII 220 1997 314

ENSCO 105* 110 2002 142

Bob Palmer 240 2000 326

Tonala* 117 2002 151

Scooter Yeargain 95 2001 126

Bob Keller 100 2002 129

Hank Boswell 100 2002 129

Offshore Courageous 87 2005 101

Panuco 133 2005 154

Offshore Defender 87 2005 101

Offshore Resolute 143 2005 166

Ocean Scepter* 150 2005 174

Offshore Vigilant 93 2005 108

Rowan Mississippi 165 2005 191

JP Bussell 125 2004 149

Atwood Aurora 177 2006 198

Offshore Intrepid 143 2006 160

Ralph Coffman 165 2005 191

Tuxpan 190 2007 204

Rowan EXL I 175 2007 188

Rowan EXL II 175 2007 188

Rowan EXL III 175 2007 188

Joe Douglas 200 2007 215

Rowan EXL IV 175 2007 188

Perforadora Central I 195 2011 191

Average 180

Note (*): Non-LeTourneau design 

Source: Data from RigLogix, 2011; Colton, 2011.
341

Table L.4. 

Average Cost of Jackup Rigs Built in the U.S. by Water Depth and Class, 1996–2011

Source: Data from RigLogix, 2011; Colton, 2011.

Water depth 

(ft)

Number Average cost 

(million $)

Standard deviation 

(million $)

300 4 133 11

350 13 164 38

375 5 176 27

400 3 270 68

550 1 326

Rig Class

KFELS B Class 2 147 6

KFELS B Class (Super) 1 174

LeTourneau 240C 3 199 14

LeTourneau Super 116 5 127 33

LeTourneau Super 116E 8 188 15

LeTourneau Super Gorilla 219-C 2 309 6

LeTourneau Super Gorilla XL 224-C 1 326

LeTourneau Tarzan Class 225-C 4 133 11
342

Table L.5.

Cost of Labor at U.S. Shipyards, 2002–2009 

Year Number of 

employees

Total compensation 

($1000)

USD per 

employee

Inflated USD 

per employee

Inflated USD 

per h**

2009 100,372 7,597,040 75,689 75,689 37.8

2008 106,049 7,074,944 66,714 70,263 35.1

2007 96,955 6,186,983 63,813 69,795 34.9

2006 85,262 5,111,697 59,953 68,398 34.2

2005 84,407 5,028,646 59,576 70,769 35.4

2004 87,111 4,904,367* 56,300 68,925 34.5

2003 86,155 4,799,634* 55,709 71,647 35.8

2002 87,152 4,694,721* 53,868 69,922 35.0

Note: (*) Total compensation estimated as payroll plus 30%. (**) Assumes employees work an 

average of 2,000 hours per year. 

Source: USDOC, Census, 2009.

Table L.6.

Labor Requirements per Unit of Shipment Value, 2002–2009 

Year Inflated shipment 

value ($1000)

Number of 

employees

USD of shipment 

value per h labor*

2009 21,801,484 100,372 109

2008 22,192,036 106,049 105

2007 18,833,866 96,955 97

2006 16,657,923 85,262 98

2005 16,225,604 84,407 96

2004 16,073,195 87,111 92

2003 16,659,085 86,155 97

2002 16,598,108 87,152 95

Note: (*) Assumes employees work an average of 2,000 hours per year. 

Source: USDOC, Census, 2009.
343

Table L.7. 

Weight Distribution of Selected Jackups 

Massie and 

Liu, 1990 

Cassidy et 

al., 2004 

William et 

al., 1999 

PetroProd, 2009; 

Yang et al., 2002 

Global 

Chimaks, 2009 

Rig type Generic Generic Generic CJ70 F&G L780 

Environmental design Moderate Harsh Harsh Harsh Moderate 

Hull mass, tons (%) 5,000 (41) 17,577*(65) 17,700* 

(73)

11,221 (39) 4,219 (58) 

Leg mass, tons (%) 1,400 (34) 3,141 (35) 2,123 (26) 2,255 (24) 585(24) 

Machinery, tons (%) 3,000 (25) 10,614 (37) 1,270 (17) 

Lightship (tons) 12,200 27,000 24,069 28,600 7,267 

Note: (*) Includes machinery. 

Table L.8. 

Steel Grade Distribution of a 300 ft Moderate Environment Jackup 

Steel Grade 

(ksi) 

Weight 

(tons) 

Percent of total 

weight (%) 

Use 

34 to 51 5,130 53 Hull, jackhouse, cantilever 

72 to 90 652 7 Jackhouse, hull, cantilever, legs, spudcans 

100 2,254 23 Legs 

Total steel weight 8,036 

Total weight 9,700 

Source: Industry personnel. 

Table L.9. 

Installed Power of Selected Jackup Rig Designs 

Rig Installed Power (kW) 

LeTourneau Super 116E 8,015 

KFELS Super B Class 9,145 

Gusto MSC CJ70 10,500 

Gusto MSC CJ46 8,600 

KFELS N Class 9,600 

LeTourneau 240C 9,150 

Source: Specification sheets. 
344

Table L.10.

LeTourneau Super 116E Rig Kit Costs 

Year Kit cost 

(million $)

Number 

of kits

Rig cost 

(million $)

Kit percent of 

cost (%)

Inflated kit 

cost (million $)

Builder

2005 26 5 90–50 18–30 33 Keppel AmFELS

2007 40 1 168 24 44 Lamprell

2007 60* 4 175 33 66 Keppel AmFELS

2009 92* 2 92 Petrobras

2009 40 1 180 22 40 Petro Vietnam

Note (*): Includes drilling equipment. 

Source: Industry press.

Table L.11. 

Contract Costs of Jackup Drilling Equipment 

Supplier Buyer Contract 

year

Contract scope 2010 cost*

(million $)

Varco Hyundai Heavy 

Industries

2001 37

National 

Oilwell

Global Sante Fe 2001 28

National 

Oilwell

COSL 2004 42

Varco Gulf Drilling 

International

2004 BOP, topdrive, drawworks, 

pipe handling, derrick, mud 

pumps, solids control, drilling 

control

22

Varco ENSCO 2004 BOP, topdrive, drawworks, 

solids control, pipe handling

20

Varco Keppel 2004 Solids control, topdrive, 

drilling control

15

Aker Maersk 2005 Derrick, BOP handling 18

TTS Energy Jurong 2007 All drilling equipment 71

EMER Yantai Raffles 2007 Drilling equipment, cantilever 33

TSC Yantai Raffles 2010 Drilling and power systems 39

TTS Energy DSIC 2010 38

TTS Energy Jurong 2011 All drilling equipment 62

TSC Yantai Raffles 2011 Drilling and power systems 29

Average 35

Note (*): Data inflated using the BLS Oil and Gas Field Machinery Equipment price index. 

Source: Industry press.
345

Table L.12. 

Costs of Selected Jackup Rig Drilling Equipment in 2010

Equipment Unit cost

($1,000)

Typical 

number

Total Cost 

($1,000)

Top drive 3,312 1 3,312

BOP 2,650 2 5,299

Choke manifold 1,332 1 1,332

BOP handler 814 2 1,627

Mud pump 1,920 3 5,759

Note: Modified from Robertson, 2003 using the BLS oilfield 

equipment price index. 

Source: Robertson, 2003; USDOL, BLS, 2011b.

Table L.13. 

Labor Cost Estimates for a Hypothetical LeTourneau 

Super 116E Jackup in Million U.S. Dollars 

Table L.14. 

Steel Costs for a Hypothetical LeTourneau Super 116E Jackup 

Total weight 

(tons)

Component Proportion of 

lightship weight (%)

Unit cost

($/ton)

Cost range 

(million $)

12,575 Legs 20–30 4,000–7,000 10.0–26.4

Hull 40–60 700–1,100 3.5–8.3

Misc. steel 5–10 1,000–1,500 0.6–1.8

Total 14.1–36.5

Labor cost

Productivity

($ value/hour)

34

($/h)

36

($/h)

38

($/h)

90 62 66 69

100 56 59 62

110 51 54 57
346

Table L.15. 

Distribution of Construction Costs for a Hypothetical LeTourneau Super 116E 

Component Cost range 

(million $)

Proportion of 

total costs (%)

Industry estimate 

(million $)

Labor 51–69 31–42 50–55

Rig Kit (including leg steel) 25–45 15–27 35–40

Drilling equipment 25–50 12–30 40

Hull and miscellaneous steel 4–10 2–5

50–55 Engines 4–6 2–4

All other material 33–41 20–25

Profit 8–16 5–10

Total 145–237 175–190

Source: Authors’ estimates; Holcomb, 2011; Smith, 2011. 

Table L.16. 

Jackup Drilling Rig Market Revenue in Million U.S. Dollars 

Annual 

delivery 

value

Threeyear 

average

Vicksburg 

three-year 

average

Brownsville 

three-year 

average

2000 305

2001 314

2002 142 254 206 47

2003 326 261 213 47

2004 277 248 151 98

2005 129 244 194 50

2006 129 178 128 50

2007 356 205 137 67

2008 986 490 208 283

2009 351 564 228 336

2010 768 702 177 525

2011 403 507 135 372

Average 374 365 168 194

Source: Authors’ estimates.
347

Table L.17. 

Estimated Employment in the U.S. Jackup Rig Construction Industry 

Employment (FTE)

Year Revenue

($ million)

Productivity 

90 $/h

Productivity 

100 $/h

Productivity 

110 $/h

2002 254 1,411 1,270 1,155

2003 261 1,450 1,305 1,186

2004 248 1,378 1,240 1,127

2005 244 1,356 1,220 1,109

2006 178 989 890 809

2007 205 1,139 1,025 932

2008 490 2,722 2,450 2,227

2009 564 3,133 2,820 2,564

2010 702 3,900 3,510 3,191

Average 507 2,817 2,535 2,305

Source: Authors’ estimates.

Table L.18. 

Jackup Related Full Time Equivalent Employment 

LeTourneau AmFELS

Productivity

($ revenue/hour labor)

90 110 90 110

2000 1146 938 263 215

2001 1185 970 263 215

2002 837 685 543 444

2003 1076 880 280 229

2004 711 582 280 229

2005 763 624 374 306

2006 1154 944 1570 1285

2007 1269 1038 1867 1527

2008 983 805 2915 2385

2009 752 615 1719 1406

2010 398 326 1770 1448

Source: Authors’ estimates. 

Source: Almeida, 2012.
348

Figure L.1. Drilling equipment; clockwise from upper left; mud pumps, top drive, shale shaker, drawworks. 

Source: NOV, 2011; GN Solids Control, 2011.
349 

Figure L.2. Locations of major suppliers for the jackup rig industry in the U.S. 

Drilling systemsEngines and generatorsHigh yield steel mill

Shipyard

Source: Kelly, 1997; Loadmaster, 2012; Caterpillar, 2012; Almeida, 2012. 
350

Figure L.3. Distribution of capital costs for jackup rig construction. 

Drilling equipment Rig kit

Derrick

Mud 

pumps

BOP

Drawworks

Design 

license

Jacking 

system

Leg 

members

Steel

Labor

Other 

equipment

Profit

Engines

Material

Total Cost
351

Figure L.4. BLS producer price indices related to jackup construction, 2000–2011. 

Source: USDOL, BLS, 2011b.
352

Figure L.5. Jackup construction revenue generated by Brownsville and Vicksburg shipyards, 

2002–2012. 
APPENDIX M 

CHAPTER 13 TABLES AND FIGURES 
355

Table M.1. 

Construction Cost Distribution for Jackups and Floaters 

Floaters* Jackups*

Cost 

(million $)

Proportion 

(%)

Cost 

(million $)

Proportion 

(%)

Steel 25–60 <10 15–40 10–20

Labor 50–120 10–15 15–55 10–30

Drilling equipment 100–200 20–30 20–70 10–30

All other equipment 100–200 20–30 35–50 20–30

Profits 50–75 <10 10–25 <10

Total 500–700 100 175–225 100

Note: (*) Estimates are for a typical $500 -$750 million floater and a $175-225 million jackup. 

Table M.2. 

Jackup Design Class Properties and Newbuild Cost in 2011

Design Number Price

(million $)

Water depth

(ft)

Harsh VDL 

(tons)

Friede & Goldman JU-2000E 11 190–220 400 Y 7,000

LeTourneau Super 116E Class 12 159–210 200–375 N 3,750

KFELS B Class 20 180–210 350–400 N 4,500

PPL Shipyard Pacific Class 400 3 190 400 N 3,750

Friede & Goldman JU-2000A 4 220–229 350 Y 4,500

Friede & Goldman JU-3000N 6 220–245 400 N 7,000

KFELS Super A Class 5 230–260 400 Y 7,000

LeTourneau 240-C Workhorse 3 194–257 400 N 3,000

GustoMSC CJ70 3 500–530 492 Y 7,000

Source: Jefferies and Company, Inc., 2011; Industry press. 
356

Table M.3. 

Semisubmersible Design Class Properties and Newbuild Cost in 2011 

Design Number Price 

(million 

$)

Water depth 

(ft)

Harsh VDL 

(tons)

Displacement 

(tons)

GVA 7500-N 2 526–709 10,000 Y 8,250 62,000

F&G ExD 3 599–771 7,500–10,000 N 10,000 58,000

Ensco 8500 2 537–560 8,500 N 8,000

CS-50 MkII (N) 2 510–526 9,843–10,000 Y 6,800 47,000

Sevan Drilling 

650

3 526–685 10,000 N 22,000 61,000

GM 4000 2 460–560 1,640–4,000 Y 5,000 42,000

GVA 4000 NCS 2 565 1,640 Y 60,000

Source: Jefferies and Company, Inc., 2011; Industry press. 

Table M.4. 

Drillship Design Class Properties and Newbuild Cost in 2011

Design Number Price 

(million $)

Water depth (ft) Harsh VDL (tons) Displacement 

(tons)

DSME 10000 2 579 10,000 N 24,000 112,000

DSME 12000 6 590–782 10,000–12,000 N 24,000 112,000

GustoMSC P10000 11 590–630 10,000–12,000 N 20,000 75,000

GustoMSC PRD12,000 1 632 12,000 N 15,000 45,000

Samsung 10000 17 638–820 10,000–12,000 N 22,000 105,000

Samsung 12000 8 550–650 10,000–12,000 N 22,000 105,000

Stena/Samsung 1 1,150 7,500 Y 19,000 108,000

Huisman GT-10000 2 550–585 10,000 N 20,000 60,000

Source: Jefferies and Company, Inc., 2011; Industry press. 
357

Figure M.1. Number and cost of worldwide jackup and floater orders, 2000–2011. 

Source: Data from RigLogix, 2011.

Number ordered
358

Figure M.2. Domestic U.S. steel prices 2000–2011. 

Figure M.3. Asian steel index and average world jackup prices, 2000–2010. 

0

50

100

150

200

250

2000 2002 2004 2006 2008 2010

Average jackup price (million $) 

or Asian Steel index

Average jackup

price

y = 0.8535x - 4.175

R2 = 0.6965

0

50

100

150

200

250

Average jackup price (million $)

0 100 200 300

Asian steel index

Source: Data from Steel Business Briefing, 2011.

Source: Data from RigLogix, 2011; Steel Business Briefing, 2011.
359

Figure M.4. BLS oil and gas field machinery equipment producer price index, 1990–2011. 

Figure M.5. Relationship between the BLS oil and gas machinery equipment index and 

global jackup prices. 

Jackups

Source: USDOL, BLS, 2011b.

Source: USDOL, BLS, 2011b; RigLogix, 2011.
360

Figure M.6. Annual compensation in U.S., Korean, and Singaporean shipyards, 2002–2010. 

Figure M.7. Productivity in the shipbuilding sector in the U.S., Korea, and Singapore, 2002–2010. 

Source: USDOL, BLS, 2011c; Wong and Chang, 2011.

Source: USDOL, BLS, 2011c; Wong and Chang, 2011.
361

Figure M.8. Revenue generated per U.S. dollar spent on labor in U.S., Korean, and Singaporean 

shipyards, 2002–2010. 

Source: USDOL, BLS, 2011c; Wong and Chang, 2011.
APPENDIX N 

CHAPTER 14 TABLES AND FIGURES 
365

Table N.1. 

Newbuild and Replacement Cost and Selected Sample Statistics in 2009 

Newbuild Replacement

Drillship Semi Jackup Drillship Semi Jackup

Cost 

(million $)

Average 672 553 225 470 366 142

Standard deviation 53 102 104 114 87 32

Coefficient of variation 0.08 0.18 0.46 0.24 0.24 0.23

Water 

depth (ft)

Average 10,135 8,333 362 8,256 4,352 293

Standard deviation 1,585 2,192 42 2,815 2,902 71

Coefficient of variation 0.16 0.26 0.12 0.34 0.67 0.24

Age (yr) Average 16 24 24

Standard deviation 12.4 10.8 10.1

Coefficient of variation 0.78 0.45 0.42

Note: Newbuild statistics based on 39 jackups, 35 semis and 37 drillships. Replacement statistics based 

on 282 jackups, 149 semis and 35 drillships. 

Source: Jefferies and Company, Inc., 2009; Industry press.

Table N.2. 

Newbuild Jackup and Semisubmersible Average Costs by 

Water Depth and Environmental Design Conditions in 2009

Water depth

(ft)

Harsh

(million $)

Moderate

(million $)

Jackups ≤ 300 - 171 (7)

300–350 240 (2) 173 (13)

350–400 465 (1) 213 (12)

≥400 530 (3) -

Semis ≤ 2,500 375 (3) -

2,500–7,500 633 (1) 542 (3)

≥7,500 585 (9) 563 (19)

Note: Sample sizes in parenthesis. 

Source: Jefferies and Company, Inc., 2009.
366

Table N.3. 

Newbuild Costs by Country of Shipyard in Million U.S. Dollars in 2009 

Rig type Water 

depth 

(ft)

Harsh India US China Singapore UAE Korea Italy Average

Jackup ≤350 Y 240 (2) 240

N 182 (1) 178 (5) 163 (5) 174 (9) 172

350–400 Y 465 (1) 465

N 223 (2) 212 (10) 213

≥400 Y 607 (1) 473 (2) 530

N

Semi ≤2,500 Y 375 (3) 375

N

2,500–

7,500

Y 633 (1) 633

N 574 (2) 480 (1) 542

≥7,500 Y 557 (5) 623 (3) 615 (1) 585

N 604 (9) 517 (7) 547 (3) 563

Drillship 7,500 N 683 (5) 683 

10,000

Y 1,500 

(1)

1,500 

N 676 (23) 676 

12,000 N 616 (2) 700 (6) 681

Note: Sample sizes in parentheses. 

Source: Jefferies and Company, Inc., 2009; Industry press.
367

Table N.4. 

Models of Jackup Newbuild Costs 

Cost (million $) = α0 + α1HARSH + α2WD + α3WD2

Model α0 α1 α2 α3 R

2 Model p SE

A 1248** 140.4** -6.88** 0.011** 0.91 ** 31.5

B -209.9** 171.7** 1.128** 0.83 ** 42.9

C -16.0 163.38** 0.0016** 0.85 ** 40.1

D 0 159.9** -0.146 0.002** 39.8

E 0 201.6** 0.54** 47.7

F 0 167.8** 0.0015** 39.7

Note (*): p is less than 0.05; (**): p is less than 0.01. Terms without asterisks are not significant. 
368

Table N.5. 

Models of Semisubmersible Newbuild Costs 

Cost (million $) = α0 + α1WD + α2YEAR

Model α0 α1 α2 R

2 Model p SE

A -50.3 0.025** 38.1* 0.39 ** 81.2

B 0 0.024** 33.6** 79.5

Note (*): p is less than 0.05; (**): p is less than 0.01. 

Table N.6. 

Jackup Newbuild Costs by Design Class 

Cost (million $) = 213** + α1DESIGN

Class α1

MSC CJ70 394.0**

F&G 2000A 27.0*

F&G Super M2 -41.6**

KFELS ModVB -11.3

KFELS N class 270.0**

LET 116 -33.8**

LET 240 9.5

MSC CJ 46 -55.0**

Pacific Class 375 0.0**

Note (*): p is less than 0.05; (**): p is less than 0.01. 

Table N.7. 

Jackup Replacement Cost Models 

Cost (million $) = α0 + α1WD + α2WD2+ α3HARSH + α4YEAR

Model α0 α1 α2 α3 α4 R

2 Model p SE

A -1243.7** 0.0005** 10.6** 0.674** 0.70 ** 17.5

B -1567** 0.282** 10.6** 0.818** 0.68 ** 18.0

C 0 0.0006** 10.6** 0.04** 18.2

Note (*): p is less than 0.05; (**): p is less than 0.01. Terms without asterisks are not significant. 
369

Table N.8. 

Semisubmersible Replacement Cost Models 

Cost (million $) = α0 + α1WD + α2YEAR + α3HARSH

Model α0 α1 α2 α3 R

2 Model p SE

A -4121 ** 0.020** 2.2 ** 23.8** 0.69 ** 48.3

B 0 0.023** 0.13** 52.4

Note (*): p is less than 0.05; (**): p is less than 0.01. 

Table N.9. 

Drillship Replacement Cost Models 

Cost (million $) = α0 + α1HARSH + α2WD 

Model α0 α1 α2 R

2 Model p SE

A 204.4 ** 196** 0.031 ** 0.65 ** 67.2

B 0 234.7* 0.053** 94.0

Note (*): p is less than 0.05; (**): p is less than 0.01. Terms without asterisks are 

not significant. 
370

Figure N.1. Distribution of jackup and floater newbuild costs. 

0

2

4

6

8

10

12

14

16

<150 150 to 175 175 to 200 200 to 225 225 to 250 250 to 275 275 to 300 >300

Number in sample

Newbuild cost (million $)

Jackups

0

2

4

6

8

10

12

14

<400 400 to 450 450 to 500 500 to 550 550 to 600 600 to 650 650 to 700 700 to 750 750 to 800 >800

Number in sample

Newbuild cost (million $)

Semi Drillship

Floaters

Source: Data from Jefferies and Company, Inc., 2009.
371

Figure N.2. Distribution of jackup and floater replacement costs. 

0

20

40

60

80

100

120

<100 100 to 120 120 to 140 140 to 160 160 to 180 180 to 200 200 to 220 >220

Number in sample

Replacement cost (million $)

0

10

20

30

40

50

60

200 to 250 250 to 300 300 to 350 350 to 400 400 to 450 450 to 500 500 to 550 550 to 600 >600

Number in sample 

Replacement cost (million $)

Semi Drillship

Jackups

Floaters

Source: Data from Jefferies and Company, Inc, 2009.
372

Figure N.3. Distribution of jackup, semisubmersible, and drillship ages for the 2009 rig fleet. 

Source: Data from Jefferies and Company, Inc., 2009.
373

Figure N.4. Relationship between water depth and cost in jackup newbuilds. 

Figure N.5. Newbuild cost model A output containing water depth and water depth squared terms. 

See Table N.4 for model A parameters. 

Source: Data from Jefferies and Company, Inc., 2009.
374

Figure N.6. Effects of time and market conditions on replacement costs. 

Figure N.7. Jackup replacement costs as a function of water depth. 

Source: Data from Jefferies and Company, Inc., 2009.
375

Figure N.8. Replacement costs of semisubmersibles and drillships as a function of water depth. 

Figure N.9. Replacement costs of drillships as a function of delivery year. 

Source: Data from Jefferies and Company, Inc., 2009.

Source: Data from Jefferies and Company, Inc., 2009.
The Department of the Interior Mission

As the Nation’s principal conservation agency, the Department of the Interior has 

responsibility for most of our nationally owned public lands and natural 

resources. This includes fostering the sound use of our land and water 

resources, protecting our fish, wildlife and biological diversity; preserving the 

environmental and cultural values of our national parks and historical places; and 

providing for the enjoyment of life through outdoor recreation. The Department 

assesses our energy and mineral resources and works to ensure that their 

development is in the best interests of all our people by encouraging stewardship 

and citizen participation in their care. The Department also has a major 

responsibility for American Indian reservation communities and for people who 

live in island communities. 

The Bureau of Ocean Energy Management 

The Bureau of Ocean Energy Management (BOEM) works to manage the 

exploration and development of the nation's offshore resources in a way that 

appropriately balances economic development, energy independence, and 

environmental protection through oil and gas leases, renewable energy 

development and environmental reviews and studies.