OCS Report 

MMS 2006-022 

Deepwater Gulf of Mexico 2006: 

America’s Expanding Frontier

Authors 

Leanne S. French 

G. Ed Richardson 

Eric G. Kazanis 

Tara M. Montgomery 

Christy M. Bohannon 

Michael P. Gravois 

U.S. Department of the Interior 

Minerals Management Service New Orleans 

Gulf of Mexico OCS Region May 2006 
The legend of the map on page 33 (Figure 21) has been emended in this electronic edition. 

ON COVER — The Holstein truss spar facility, Discoverer Deep Seas drillship, and Magnolia tension-leg platform 

(photos courtesy of BP/Marc Morrison, Transocean, and ConocoPhillips).
Table of Contents Page

iii 

PREFACE....................................................................................................................................................xi

INTRODUCTION ........................................................................................................................................1

BACKGROUND ..........................................................................................................................................3

Definitions..............................................................................................................................................3

Expanding Frontier.................................................................................................................................5

Seismic Activity .....................................................................................................................................6

Exploration Activity .............................................................................................................................10

Lower Wilcox ...........................................................................................................................10

Eastern GOM ............................................................................................................................10

Lower Miocene .........................................................................................................................10

Hydrates ....................................................................................................................................12

Leasing Activity ...................................................................................................................................14

Ocean Current Monitoring ...................................................................................................................19

Challenges and Rewards ......................................................................................................................19

LNG Projects........................................................................................................................................23

LEASING AND ENVIRONMENT............................................................................................................29

Leasing Activity ...................................................................................................................................29

Bidding and Leasing Trends.................................................................................................................30

Lease Ownership ..................................................................................................................................32

Future Deepwater Lease Activity.........................................................................................................32

Environmental Activity ........................................................................................................................35

DRILLING AND DEVELOPMENT..........................................................................................................41

Drilling Activity ...................................................................................................................................41

High Pressure, High Temperature ........................................................................................................50

Development Systems ..........................................................................................................................52

Fixed Platform ..........................................................................................................................52

Compliant Tower ......................................................................................................................52

Tension-Leg Platform ...............................................................................................................52

Semisubmersible Production Unit ............................................................................................52

Spar ....................................................................................................................................53

Subsea Trends.......................................................................................................................................63

Independence Hub................................................................................................................................63

New Pipelines.......................................................................................................................................65

High Integrity Pressure Protection System (HIPPS) ............................................................................69
Table of Contents — continued Page

iv 

RESERVES AND PRODUCTION ............................................................................................................73

Discoveries ...........................................................................................................................................73

Production Trends ................................................................................................................................77

Production Rates...................................................................................................................................84

Shallow-Water Field Versus Deepwater Field Performance................................................................91

Hurricane Activity................................................................................................................................91

Ivan ....................................................................................................................................91

Katrina and Rita ........................................................................................................................91

SUMMARY AND CONCLUSIONS .........................................................................................................95

Development Cycle ..............................................................................................................................95

Drilling the Lease Inventory...............................................................................................................101

Expanding Frontier.............................................................................................................................105

Highlights................................................................................................................................106

CONTRIBUTING PERSONNEL.............................................................................................................109

REFERENCES .........................................................................................................................................111

APPENDICES ..........................................................................................................................................113

Appendix A. Announced Deepwater Discoveries (Sorted by Project Name)..............................113

Appendix B. Chronological Listing of GOM Lease Sales by Sale Location and Sale Date. ........121

Appendix C. NTL No. 2006-G02, Suspension of Operations Based on Rig Delays, Lack of 

Rig Availability and Procurement of Long Lead Equipment. .................................123

Appendix D. Deepwater Studies Program .....................................................................................125

Appendix E. Subsea Completions. ................................................................................................131

Appendix F. Annual GOM Oil and Gas Production. ....................................................................141

Appendix G. GOM Platforms Destroyed by Hurricanes (2004-2005) ..........................................143
Figures Page

v 

Figure 1. The Gulf of Mexico OCS is divided into Western, Central, and Eastern Planning Areas. 

Water-depth categories used in this report are shown in addition to royalty relief zones 

shaded according to the Energy Policy Act of 2005............................................................... 4

Figure 2. Progressive deepwater 3-D seismic permit coverage. ............................................................ 7

Figure 3. Deepwater Gulf of Mexico 3-D seismic permit coverage from 1992 to 2005........................ 8

Figure 4. Pre-stack depth migration coverage from various industry sources. ...................................... 9

Figure 5. Stratigraphic chart highlighting new play potential.............................................................. 11

Figure 6. Frontier plays in the deepwater GOM. ................................................................................. 11

Figure 7. Schematic Wilcox depositional model with key trend wells (graphic courtesy of 

Chevron) ............................................................................................................................... 12

Figure 8. Location of known gas hydrates in the Gulf of Mexico. ...................................................... 15

Figure 9. Deepwater leases issued in the Gulf of Mexico.................................................................... 16

Figure 10. Active leases in the Gulf of Mexico. .................................................................................... 18

Figure 11. Loop and eddy currents in the Gulf of Mexico (image courtesy of Johns Hopkins 

University). ........................................................................................................................... 20

Figure 12. Deepwater discoveries in the Gulf of Mexico. ..................................................................... 21

Figure 13. Ownership of deepwater discoveries (includes industry-announced discoveries)................ 22

Figure 14. Estimated volume of 87 proved deepwater fields................................................................. 24

Figure 15. Onshore service bases for existing deepwater structures...................................................... 25

Figure 16. Onshore service bases for pending deepwater plans............................................................. 26

Figure 17. Current, potential, and future hub facilities in the Gulf of Mexico. ..................................... 27

Figure 18. Number of leases issued each year, subdivided by DWRRA water-depth categories.......... 30

Figure 19. Number of leases issued each year in depths greater than 800 m, subdivided by waterdepth categories specified in the Energy Policy Act of 2005. .............................................. 31

Figure 20. Number of leases bid on for each deepwater interval........................................................... 31

Figure 21. Ownership of deepwater leases............................................................................................. 33

Figure 22. Anticipated lease expirations in the Gulf of Mexico. ........................................................... 34

Figure 23. Grid EA status....................................................................................................................... 36

Figure 24. ROV surveys including known chemosynthetic communities. ............................................ 39

Figure 25. The Deepwater Horizon, a dynamically positioned, semisubmersible drilling unit (photo 

courtesy of Transocean)........................................................................................................ 42

Figure 26. The Discoverer Enterprise, a double-hulled, dynamically positioned drillship (photo 

courtesy of Transocean)........................................................................................................ 42

Figure 27. Average number of rigs operating in the deepwater GOM................................................... 43

Figure 28. Approximate number of deepwater rigs (GOM and worldwide) subdivided according to 

their maximum water-depth capabilities. Inset shows the number of deepwater rigs in 

various locations. .................................................................................................................. 43

Figure 29. All deepwater wells drilled in the Gulf of Mexico, subdivided by water depth. .................. 44
Figures — continued Page

vi 

Figure 30. All deepwater wells drilled from January through June in the Gulf of Mexico by water 

depth. .................................................................................................................................... 45

Figure 31. All deepwater wells drilled from July through December in the Gulf of Mexico by water 

depth. .................................................................................................................................... 45

Figure 32. All deepwater exploratory wells drilled in the Gulf of Mexico by water depth. .................. 47

Figure 33. All deepwater development wells drilled in the Gulf of Mexico by water depth................. 47

Figure 34. Deepwater exploratory wells drilled in the Gulf of Mexico. ................................................ 48

Figure 35. Deepwater development wells drilled in the Gulf of Mexico............................................... 49

Figure 36. Deepwater EP’s, DOCD’s, and DWOP’s received in the Gulf of Mexico since 1992......... 50

Figure 37. Estimated bottomhole pressure (psi) versus total vertical depth........................................... 51

Figure 38. Bottomhole temperature (oF) versus total vertical depth. ..................................................... 51

Figure 39. Deepwater development systems.......................................................................................... 55

Figure 40. Three development systems: a TLP installed at Magnolia field, a semisubmersible at 

Thunder Horse field, and a truss spar installed at Holstein field (images courtesy of 

ConocoPhillips and BP/Marc Morrison). ............................................................................. 60

Figure 41. Progression of spar deepwater development systems (image courtesy of Technip)............. 61

Figure 42. The number of subsea projects and hubs for 5-year periods by water-depth category......... 62

Figure 43. Production systems for currently producing fields, including subsea systems..................... 62

Figure 44. Crosby Project (MC 899) subsea equipment layout (image courtesy of Shell 

International Exploration and Production Inc.). ................................................................... 64

Figure 45. Number of shallow- and deepwater subsea completions each year...................................... 66

Figure 46. Maximum water depth of subsea completions installed each year....................................... 66

Figure 47. Water depth of subsea completions. ..................................................................................... 67

Figure 48. Length of subsea tiebacks..................................................................................................... 67

Figure 49a. Approved deepwater oil and gas pipelines less than or equal to 12 inches in diameter. ...... 68

Figure 49b. Approved deepwater oil and gas pipelines greater than 12 inches in diameter. ................... 68

Figure 50. Oil and gas pipelines with diameters greater than or equal to 20 inches. ............................. 70

Figure 51. Deepwater oil and gas pipelines in the Gulf of Mexico........................................................ 71

Figure 52. Proved reserve additions....................................................................................................... 74

Figure 53. Proved and unproved reserve additions. ............................................................................... 74

Figure 54. Average field size using proved and unproved reserves....................................................... 75

Figure 55. Number of deepwater field discoveries and resulting number of producing fields. ............. 75

Figure 56. Number of deepwater field discoveries and new hydrocarbons found (MMS reserves, 

MMS resources, and industry-announced discoveries). ....................................................... 76

Figure 57. BOE added (reserves, known resources, and industry-announced discoveries)................... 76

Figure 58. Relative volume of production from each GOM lease. Bar heights are proportional to 

total lease production (barrels of oil equivalent) during that interval................................... 78

Figure 59. Estimated U.S. oil and gas production in 2004..................................................................... 81
Figures — continued Page

vii 

Figure 60a. Comparison of average annual shallow- and deepwater oil production. .............................. 82

Figure 60b. Comparison of average annual shallow- and deepwater gas production. ............................. 82

Figure 61a. Contribution of DWRRA oil production to total oil production in water depths greater 

than 200 m (656 ft). .............................................................................................................. 83

Figure 61b. Contribution of DWRRA gas production to total gas production in water depths greater 

than 200 m (656 ft). .............................................................................................................. 83

Figure 62a. Contributions from subsea completions toward total deepwater oil production................... 85

Figure 62b. Contributions from subsea completions toward total deepwater gas production. ................ 85

Figure 63a. Maximum production rates for a single well within each water-depth category for 

deepwater oil production. ..................................................................................................... 86

Figure 63b. Maximum production rates for a single well within each water-depth category for 

deepwater gas production. .................................................................................................... 86

Figure 64a. Average production rates for shallow-water and deepwater oil well completions. .............. 87

Figure 64b. Average production rates for shallow-water and deepwater gas well completions.............. 87

Figure 65a. Deepwater oil production profiles (oil wells coming onstream between 1992 and 2004).... 88

Figure 65b. Shallow-water oil production profiles (oil wells coming onstream between 1992 and 

2004)..................................................................................................................................... 88

Figure 66a. Maximum historic oil production rates for Gulf of Mexico wells........................................ 89

Figure 66b. Maximum historic gas production rates for Gulf of Mexico wells....................................... 90

Figure 67a. Cumulative oil production and ultimate recoverable reserves for selected shallow-water 

and deepwater fields. ............................................................................................................ 92

Figure 67b. Cumulative gas production and ultimate recoverable reserves for selected shallow-water 

and deepwater fields. ............................................................................................................ 92

Figure 68. Platforms within the path of Hurricanes Katrina and Rita in the Gulf of Mexico................ 93

Figure 69a. Comparison of total GOM oil shut in and GOM deepwater oil shut in................................ 94

Figure 69b. Comparison of total GOM gas shut in and GOM deepwater gas shut in.............................. 94

Figure 70. Deepwater projects that began production in 2004 and 2005 and those expected to begin 

production by yearend 2011. ................................................................................................ 96

Figure 71. Deepwater lease activity and oil/natural gas prices (prices from U.S. Energy 

Information Administration: oil through December 2005 and natural gas through 

October 2005). ...................................................................................................................... 97

Figure 72. Lag from leasing to first production for producing deepwater fields. .................................. 99

Figure 73. Year in the lease term in which BOE was discovered and percent of leases were tested, 

for deepwater leases, 1974-1995. ....................................................................................... 100

Figure 74. Activity on deepwater leases. ............................................................................................. 102

Figure 75. Leases drilled and barrels found. ........................................................................................ 103

Figure 76a. Relationship between number of leases issued and number of leases drilled, 1974-1995. 104

Figure 76b. Relationship between number of leases issued and number of resulting producing 

leases, 1974-1995. .............................................................................................................. 104
Figures — continued Page

viii 

Figure 76c. Relationship between number of leases drilled and number of resulting producing 

leases, 1974-1995. .............................................................................................................. 104

Figure 77. The challenge of deepwater lease evaluation...................................................................... 105

Figure 78. Comparison of 2000, 2002, 2004, and 2006 deepwater GOM reports: successive 

increases in deepwater BOE. .............................................................................................. 106
Tables Page

ix 

Table 1 List of 2005 Deepwater Discoveries....................................................................................... 2

Table 2 List of Deepwater Discoveries in Water Depths Greater than 7,000 ft (2,134 m)................ 13

Table 3 Number of Active Leases by Water-Depth Interval ............................................................. 14

Table 4 LNG Projects Proposed or Licensed in the Gulf of Mexico................................................. 23

Table 5 Deepwater Royalty Relief By Water-Depth Range.............................................................. 29

Table 6 Completed Grid PEA’s Within the Central and Western Planning Areas of the Gulf of 

Mexico .................................................................................................................................. 37

Table 7 Development Systems of Productive Deepwater GOM Projects.......................................... 56

Table 8 Independence Hub Anchor Fields......................................................................................... 65

Table 9 Top 20 Producing Blocks for the Years 2003–2004............................................................. 77
xi 

PREFACE 

This publication is the sixth that the Minerals Management Service (MMS) has released recounting the 

impressive levels of deepwater exploration and development activity in the Gulf of Mexico (GOM). The 

GOM is in its eleventh year of sustained expansion in deepwater. 

Since the first major deepwater leasing boom in 1995 and 1996, we have entered into a sustained, robust 

expansion of activity. The Central Gulf of Mexico Sale 198 held this past March garnered bids on 204 

deepwater blocks, confirming continued enthusiasm for exploring the deepwater arena. Indeed, Amerada 

Hess placed a high bid of $42.7MM on the deepwater Block Green Canyon 287, the highest bid seen in 

20 years. The total of the high bids in the sale, including shallow- and deepwater leases, was $588 

million, the highest in eight years. 

As of March 2006, there were 118 deepwater hydrocarbon production projects on line. Production from 

deepwater was an estimated 950 thousand barrels of oil per day and 3.8 billion cubic feet of natural gas 

per day by the end of 2004. Production would have been even greater if not for shut-in production caused 

by Hurricane Ivan. Production statistics from 2005 will be similarly impacted by Hurricanes Katrina and 

Rita. 

More than 980 exploration wells have been drilled in the deepwater Gulf since 1995. At least 126 

deepwater discoveries have been announced since then. Significantly, in the last seven years, there have 

been 22 industry-announced discoveries in water depths greater than 7,000 feet (2,134 meters), seven in 

2004 alone. 

The state-of-the-art technology that has been developed to drill and produce the Gulf of Mexico 

deepwater resources is at the leading edge of the world’s engineering feats. Production from spars has 

increased so that fourteen spars were in production as of March 2006. Although most of the spars are 

either classic spars or truss spars, the world’s first cell spar was installed by Kerr-McGee in 2004. The 

potential use of floating production, storage, and offloading (FPSO) systems is being discussed, and the 

first application to use this technology may be filed with MMS in 2006. 

The MMS plays a critical role in this energy expansion by ensuring the receipt of fair market value for the 

sale of leases, evaluating and approving new technology, and facing new challenges regulating the 

drilling and production of prospects in ever deepening water depths. The MMS’s development of 

environmental review procedures to ensure timely but thorough review of projects while continuing to 

protect the environment has been innovative and critical to keep deepwater project timelines minimized. 

Chris C. Oynes

Regional Director

Minerals Management Service
1 

INTRODUCTION 

The deepwater Gulf of Mexico (GOM) is an integral part of the Nation’s oil and gas supply and one of the 

world’s most important oil and gas provinces. A major milestone was reached early in 2000 when more 

oil was produced from the deepwater GOM than from the shallow-water GOM. Deepwater oil production 

has nearly reached the all-time shallow-water GOM record set in 1971. In addition, the average size of a 

deepwater GOM field discovery is several times larger than the average shallow-water discovery. 

Deepwater fields are some of the most prolific producers in the GOM. 

This report is divided into five sections. 

The Background section discusses 

• highlights of current deepwater GOM activity, 

• new discoveries, 

• technology concerns, 

• the existing deepwater infrastructure, and 

• LNG projects. 

The Leasing and Environment section discusses 

• historical water-depth and bidding trends in deepwater leasing, 

• leaseholdings of major oil companies compared with those of nonmajor oil 

companies, 

• future deepwater lease activity, 

• royalty relief under Energy Policy Act of 2005, and 

• environmental activity. 

The Drilling and Development section discusses 

• deepwater drilling activity, 

• historical drilling statistics, 

• the transition to deeper wells and deeper water, 

• high-pressure, high-temperature environments, 

• deepwater development systems, 

• subsea trends, 

• Independence Hub, and 

• pipelines and HIPPS. 

The Reserves and Production section discusses 

• historical deepwater reserve additions, 

• large future reserve additions associated with recently announced discoveries, 

• discoveries in new, lightly tested plays with large potential, 

• historical trends in deepwater production, 
2 

• comparison of shallow-water and deepwater production, 

• effects of Hurricanes Ivan, Katrina, and Rita on production, and 

• high deepwater production rates. 

The Summary and Conclusions section discusses 

• increasing deepwater oil and gas production and anticipated new fields, 

• expected increases in deepwater discoveries (these expectations are based on drilling 

of the large deepwater lease inventory), 

• lags between leasing and drilling and between drilling and initial production, 

• difficulties evaluating deepwater leases before their terms expire, and 

• significant changes since the 2004 report. 

Table 1 

List of 2005 Deepwater Discoveries 

Project Name Area/Block Water Depth (ft) Operator 

Anduin MC 755 2,400 Nexen 

Big Foot WR 29 5,286 Chevron 

Clipper GC 299 3,452 Pioneer 

Genghis Khan GC 652 4,300 Anadarko 

Jubilee Extension LL 309 8,774 Anadarko 

Knotty Head GC 512 3,557 Chevron/Unocal 

Mondo NW Extension LL 1 8,340 Anadarko 

Q MC 961 7,925 Spinnaker 

Stones WR 508 9,556 BP 

Wrigley MC 506 3,700 Newfield 

GC = Green Canyon 

LL = Lloyd Ridge 

MC = Mississippi Canyon 

WR = Walker Ridge 
3 

BACKGROUND 

DEFINITIONS

The GOM Outer Continental Shelf (OCS) is divided into the Western, Central, and Eastern Planning 

Areas (figure 1). Many of the data presented in this report are subdivided according to water depth. 

These divisions (1,000, 1,500, 5,000, and 7,500 ft) are illustrated in figure 1, along with the new royalty 

relief zones of the Energy Policy Act of 2005 (200, 400, 800, 1,600, and 2,000 m) for reference. Not all 

leases within a colored area are eligible for royalty relief because of the different vintage of leases 

included within the area. As a whole, the new relief zones have not been incorporated into the statistical 

analyses included in this report. Royalty relief volumes were changed with the passage of the Act. 

Details of these changes can be found in the Leasing and Environment section of this report. 

A variety of criteria can be used to define deepwater. The threshold separating shallow- and deepwater 

can range from 656-ft (200-m) to 1,500-ft (457-m) water depth. For purposes of this report, deepwater is 

defined as water depths greater than or equal to 1,000 ft (305 m). Similarly, ultra-deepwater is difficult to 

define precisely. For purposes of this report, ultra-deepwater is defined as water depths greater than or 

equal to 5,000 ft (1,524 m). 

A few other definitions are useful at this point: 

• Proved Reserves are those quantities of hydrocarbons that can be estimated with 

reasonable certainty to be commercially recoverable from known reservoirs. These 

reserves have been drilled and evaluated and are generally in a producing or soon-tobe producing field. 

• Unproved Reserves can be estimated with some certainty (drilled and evaluated) to 

be potentially recoverable, but there is as yet no commitment to develop the field. 

• Known Resources in this report refer to discovered resources (hydrocarbons whose 

location and quantity are known or estimated from specific geologic evidence) that 

have less geologic certainty and a lower probability of production than the Unproved 

Reserves category. 

• Industry-Announced Discoveries refer to oil and gas accumulations that were 

announced by a company or otherwise listed in industry publications. These 

discoveries may or may not have been evaluated by MMS, and the reliability of 

estimates can vary widely. 

• Field is defined as an area consisting of a single reservoir or multiple reservoirs all 

grouped on, or related to, the same general geologic structural feature and/or 

stratigraphic trapping condition. There may be two or more reservoirs in a field that 

are separated vertically by intervening impervious strata or laterally by local geologic 

barriers, or by both. 

More detailed definitions may be found in the annual Estimated Oil and Gas Reserves, Gulf of Mexico 

Outer Continental Shelf, December 31, 2002 report (Crawford et al., 2005). 

This report refers to deepwater developments as both fields (as defined above) and by operator-designated 

project names. A field name is assigned to a lease or a group of leases so that natural gas and oil 

resources, reserves, and production can be allocated on the basis of the unique geologic feature that 

contains the hydrocarbon accumulation. Appendix A provides locations of these fields and projects. The 

field’s identifying block number corresponds to the first lease qualified by MMS as capable of production 

or the block where the primary structure is located. 
4



 

 

	





 
 
 


	

	



	

	

	

		 

	
	




	
	

	

	

	







 







	
	



	

	 	

	
	

		
	 



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Figure 1. The Gulf of Mexico OCS is divided into Western, Central, and Eastern Planning Areas. Water-depth cate

report are shown in addition to royalty relief zones shaded according to the Energy Policy Act of 2005. 
5 

Note that the term “oil” refers to both oil and condensate throughout this report and “gas” includes both 

associated and nonassociated gas. All production volumes and rates reflect data through December 2004 

(the most recent, complete data available at the time of this publication). 

EXPANDING FRONTIER

When the original version of this report (Cranswick and Regg, 1997) was published in February 1997, a 

new era for the GOM had just begun with intense interest in the oil and gas potential of the deepwater 

areas. There were favorable economics, recent deepwater discoveries, and significant leasing at that time. 

In February 1997, there were 17 producing deepwater projects, up from only 6 at the end of 1992. Since 

then, industry has been rapidly advancing into deepwater, and many of the anticipated fields have begun 

production. 

The previous version of this report (French et al., 2005) was an interim version of the biennial deepwater 

report published by Minerals Management Service (MMS). The interim report published in 2005 

provided a review of the deepwater frontier and highlights of 2004. This report reverts to the biennial 

format of providing trend analyses as well as advancements since the last detailed report published in 

2004 (Richardson et al.). 

At the end of March 2006, there were 118 producing projects in the deepwater GOM, up 37 percent in the 

two years since Richardson et al. (2004). Deepwater production rates rose by well over 100,000 barrels 

of oil per day (BOPD) and 400 million cubic ft of gas per day (MMCFPD), respectively, each year from 

1997 through 2002. Production rates have remained flat since 2002. 

The dramatic shift toward high activity levels in the deepwater GOM occurred during the last few years, 

although it had been developing for over two decades. Deepwater production began in 1979 with Shell’s 

Cognac field, but it took another five years before the next deepwater field (ExxonMobil’s Lena field) 

came online. Both developments relied on extending the limits of platform technology used to develop 

the GOM shallow-water areas. Deepwater exploration and production grew with tremendous advances in 

technology since those early days. This report focuses on changes during the last 14 years, 1992-2005. 

Over these last 14 years, there has been an overall expansion in all phases of deepwater activity. There 

are approximately 8,221 active leases in the Gulf of Mexico OCS, 54 percent of which are in deepwater. 

(Note that lease statuses may change daily, so the current number of active leases is an approximation.) 

Contrast this to approximately 5,600 active Gulf of Mexico leases in 1992, only 27 percent of which were 

in deepwater. On average, there were 30 rigs drilling in deepwater in 2005, compared with only 3 rigs in 

1992. Likewise, deepwater oil production rose over 840 percent and deepwater gas production increased 

about 1,600 percent from 1992 to 2002. 

Some measures of deepwater activity have declined while others have increased since the 2004 report. 

The average number of rigs operating, the number of deepwater plans submitted, and the average bid 

amount per block in the ultradeep water have increased. There have been, however, decreases in the 

average bid amount per block in water depths less than 5,000 ft and in the number of wells drilled. 

All phases of exploration and development moved steadily into deeper waters over the past 14 years. 

This trend is observable in seismic activity, leasing, exploratory drilling, field discoveries, and 

production. Major oil companies dominated deepwater leasing activity until 1996, when the activity of 

nonmajor companies increased. Indeed, nonmajors are responsible for seven of the ten deepwater 

discoveries announced in 2005. 

The OCS Deep Water Royalty Relief Act (DWRRA; 43 U.S.C. §1337) has had a significant impact on 

deepwater GOM activities. This legislation provided economic incentives for operators to develop leases 

in water depths greater than 200 m (656 ft). These incentives include the suspension of Federal royalty 

payments (for leases issued 1996-2000) on the initial 17.5 million barrels of oil equivalent (MMBOE) 
6 

produced from a lease in 200-400 m (656-1,312 ft) of water, 52.5 MMBOE for a lease in 400-800 m 

(1,312-2,624 ft) of water, and 87.5 MMBOE for a lease in greater than 800 m (2,624 ft) of water. 

Reduction of royalty payments is also available through an application process for some deepwater fields 

that were leased prior to the DWRRA but had not yet gone on production. The fixed suspension volume 

provision of the DWRRA (for new leases issued 1996-2000) expired on November 28, 2000. Leases 

acquired between November 28, 1995, and November 28, 2000, will retain the incentives until their 

expiration. Exploration and production incentives have continued since 2000 for leases in water depths 

greater than 400 m (1,312 ft). With the passage of the Energy Policy Act of 2005, lease terms for 

deepwater royalty relief were changed, eliminating the 1,600-m or deeper water-depth category and 

establishing two new royalty suspension categories: 1,600- to 2,000-m and greater than 2,000-m water 

depth. 

SEISMIC ACTIVITY

A combination of factors, including the DWRRA, key deepwater discoveries, the recognition of high 

deepwater production rates, and the evolution of deepwater development technologies, spurred a variety 

of deepwater activities. One of the first impacts was a dramatic increase in the acquisition of 3-

dimensional (3-D) seismic data (figure 2). (Note that figures 2 and 3 illustrate areas permitted for seismic 

acquisition. The actual coverage available may be slightly different than that permitted.) Threedimensional seismic data are huge volumes of digital energy recordings resulting from the transmission 

and reflection of sound waves through the earth. These large “data cubes” can be interpreted to reveal 

likely oil and gas accumulations. The dense volume of recent, high-quality data may reduce the inherent 

risks of traditional hydrocarbon exploration and allow imaging of previously hidden prospects. Figure 2 

illustrates the surge of seismic activity in the deepwater GOM during the last 14 years. Seismic 

acquisition has stepped into progressively deeper waters since 1992. Figure 3 shows the abundance of 

3-D data now available. These data blanket most of the deepwater GOM, even beyond the Sigsbee 

Escarpment (a geologic and bathymetric feature in ultra-deep water). Note that many active deepwater 

leases were purchased before these 3-D surveys were completed (only the more sparsely populated 2-D 

datasets were available). 

The seismic permitting coverage shown in figure 3 does not tell the whole story of geophysical activity in 

the deepwater GOM. Pre-stack depth migration (PrSDM) of seismic data has greatly enhanced the 

interpretation capabilities in the deepwater GOM, particularly for areas hidden below salt canopies. 

While PrSDM was once used sparingly, the availability of large speculative PrSDM surveys allows the 

widespread use of this technology in the early phases of exploration. Subsalt discoveries like Mad Dog, 

Thunder Horse, North Thunder Horse, Atlantis, and Tahiti demonstrate the importance of subsalt 

exploration. Figure 4 provides a partial inventory of PrSDM coverage. This figure provides a good 

indication of the current widespread coverage of PrSDM processing. 

Time-lapse seismic surveys (also known as 4-D) will likely be the next significant seismic technology to 

be applied routinely in the deepwater GOM. The technique can be applied to characterize reservoir 

properties, monitor production efficiency, and estimate volumetrics from inception through the life of the 

field (Shirley, 2001). At Auger field (GB 426), Shell has identified deeper targets, stranded attic 

opportunities, and unswept bypassed reserves using 4-D technology (Shirley, 2004). The high cost of 

drilling deepwater wells and the challenges associated with reentry of deepwater wells may promote the 

increased use of 4-D technology in the deepwater GOM. 

Improving seismic imaging below salt bodies is the impetus behind another technology being 

investigated, nodal seabed technology. This technology uses all-azimuth illumination to acquire seismic 

data by recording in all directions as opposed to conventional streamers, which routinely record data in a 

single direction (Durham, 2006). This new technology is currently being applied at Atlantis (GC 699) by 

Fairfield Industries and BP. 
7 

Figure 2. Progressive deepwater 3-D seismic permit coverage. 
8

Figure 3. Deepwater Gulf of Mexico 3-D seismic permit coverage from 1992 to 2005. 
9

Figure 4. Pre-stack depth migration coverage from various industry sources. 
10 

EXPLORATION ACTIVITY

Recent discoveries in new deepwater plays continue to expand the exploration potential of the deepwater 

GOM. Figure 5 indicates that 99 percent of total GOM proved reserves are in Neogene-age and younger 

reservoirs (Pleistocene, Pliocene, and Miocene); however, several recent deepwater discoveries 

encountered large potential reservoirs in sands of Paleogene age (Oligocene, Eocene, and Paleocene). 

Lower Wilcox 

The discovery of these Paleogene-age reservoirs has opened wide areas of the GOM to further drilling. 

Figure 6 illustrates two frontier deepwater plays in the GOM, the Mississippi Fan Foldbelt and the 

Perdido Foldbelt, both of which include reservoirs of Paleogene age. 

With the drilling of the Trident and Cascade discoveries (AC 903 and WR 206) in 2001 and 2002, 

respectively, the potential for areally extensive Lower Wilcox sand extending from Alaminos Canyon to 

Walker Ridge was established. Figure 7 is a schematic showing the depositional environments of the 

Wilcox from the sediment source in onshore Texas and Louisiana to the deepwater GOM. Deposition of 

the Lower Wilcox submarine fan complex appears to have been largely unaffected by salt tectonism, 

resulting in a thick amalgamated sand accumulation across a broad geographic area (Seitchik and Powell, 

2006). The Cascade discovery established the existence of turbidite sands more than 350 miles down dip 

from the source deltas in south Texas (Meyer et al., 2005). Two subsalt discoveries have also been made 

in the Lower Wilcox, St. Malo (WR 678) and Jack (WR 759). Chevron is expected to conduct a flow test 

on its Jack prospect in the very near future. To date, there are five Lower Wilcox and/or Paleogene 

discoveries in Alaminos Canyon and four Lower Wilcox discoveries in Walker Ridge. 

Although the Paleogene trend is a promising exploration target, there are many challenges to be met 

before production can begin. Appraisal wells must be drilled and wells tested to determine the reservoir 

quality and producibility of the Lower Wilcox. Other challenges include the completion and production 

of deep reservoirs in the ultradeep GOM, for which there is no existing infrastructure. 

Eastern GOM 

Figure 6 also shows a composite outline of numerous plays in the Eastern GOM; these range in age from 

Pleistocene through Jurassic. Note that the proposed change in the geographic boundary between the 

Central and Eastern GOM is not reflected here. There are three areas of interest in the Eastern GOM: 

allochthonous salt-related features, autochthonous salt-related features, and Mesozoic shelf carbonate 

plays (Denman and Adamick, 2000). These plays are within the eastern Mississippi Fan and the Florida 

carbonate shelf. Allochthonous salt-related plays are largely of early Pliocene or middle to late Miocene 

age and occur in proximity to and beneath horizontal salt features largely restricted to the upper 

Mississippi Fan. 

Successful exploration has occurred in the Eastern GOM with announced discoveries in DeSoto Canyon 

(Spiderman/Amazon and San Jacinto) and in Lloyd Ridge (Atlas, Atlas NW, Cheyenne, and Mondo 

Northwest). These discoveries, along with discoveries in Atwater Valley (Vortex, Jubilee, and 

Merganser) and Mississippi Canyon (Q) to the west (Central GOM), will comprise the anchor fields for 

Independence Hub. At least six of these discoveries encountered Miocene-age reservoirs, and all ten are 

in water depths greater than 7,800 ft (2,378 m). 

Lower Miocene 

The Mississippi Fan fold belt trend saw three Lower Miocene oil discoveries in 2005: Knotty Head (GC 

512), Genghis Khan (GC 652), and Big Foot (WR 29). A thick layer of Middle Jurassic Louann salt is 

interpreted to have deformed during the Early Cretaceous, forming a regional salt canopy. This 

allochthonous layer was critical to the formation of the fold belt (Morris et al., 2004). The folds are 

interpreted to be salt-cored and overlie the regional detachment of the Louann Salt. 
11 

Chevron’s successful production test at their Tahiti discovery well (GC 640) in 2004 undoubtedly 

undergirded further exploration of the trend. Tahiti tested a three-way structural nose, trapped against a 

salt feeder/weld system, buried beneath an 11,000-ft (3,354-m) thick salt canopy (Yip, 2006). The 

discovery well produced at a restricted rate of 15 MBOPD. Rate and pressure analyses indicate that the 

well may be capable of sustained flow of as much as 30 MBOPD. Neogene

Quaternary Tertiary 

Paleogene

Cretaceous

Jurassic

Pleistocene

Pliocene

Miocene

Oligocene

Eocene

Paleocene

99% GOM 

proved

reserves

1% GOM

proved 

reserves

- Large discoveries in Mississippi Fan Fold

 Belt.

- Large subsalt discoveries - fold belts and 

 turtle structures.

- Projection of deepwater plays updip into 

 shallower waters. Deep drilling required.

- Newly announced discoveries in the 

 deepwater open a large play area for

 exploration.

- Mesozoic potential extends into the Eastern

 GOM Sale areas.

0 mya

1.8 mya

24 mya

65 mya

144 mya

mya=million years ago 

Figure 5. Stratigraphic chart highlighting new play potential. 

Figure 6. Frontier plays in the deepwater GOM. 
12 

Figure 7. Schematic Wilcox depositional model with key trend wells (graphic courtesy of 

Chevron) 

Although not a geologic play, the ultra-deepwater areas of the GOM can also be considered “frontier 

territory.” During the last five years there have been 22 industry-announced discoveries in water depths 

greater than 7,000 ft (2,134 m), eleven of those discoveries in the last two years alone (table 2). 

Announced volumes for these discoveries are more than 1.8 billion BOE. 

In summary, the presence of pre-Miocene reservoirs, successes in the Eastern GOM sale area, and 

significant discoveries in the ultra-deepwater demonstrate the continuing exploration potential in the 

deepwater GOM. These new plays are large in areal extent, have multiple opportunities, and contain 

potentially huge traps with the possibility of billions of barrels of hydrocarbons. 

Hydrates 

In addition to the traditional oil and gas plays in the deepwater GOM, there may be significant resources 

in gas hydrates (figure 8). These resources may be 30 to 300 times greater than conventional oil and gas 

reserves. A gas hydrate is a cage-like lattice of ice that traps molecules of natural gas, primarily methane. 

Hydrates are formed near the seafloor under conditions of low temperature, high pressure, and in the 

presence of natural gas. In the GOM, hydrates occur in water depths greater than 1,450 ft (442 m). Each 

cubic foot of hydrate yields approximately 160 ft3

 of gas at standard temperature and pressure. 
13 

Table 2 

List of Deepwater Discoveries in Water Depths Greater than 7,000 ft (2,134 m) 

Project Name Area/Block Water Depth (ft) Discovery Year 

Aconcagua MC 305 7,379 1999 

Camden Hills MC 348 7,530 1999 

Blind Faith MC 696 7,116 2001 

Merganser AT 37 8,064 2001 

St. Malo WR 678 7,326 2001 

Trident AC 903 9,816 2001 

Cascade WR 206 8,143 2002 

Great White AC 857 7,425 2002 

Vortex AT 261 8,422 2002 

Atlas LL 50 9,180 2003 

Chinook WR 469 9,104 2003 

Jubilee AT 349 8,891 2003 

Spiderman/Amazon DC 621 8,100 2003 

Atlas NW LL 5 8,810 2004 

Cheyenne LL 399 8,987 2004 

Mondo Northwest LL 2 8,340 2004 

San Jacinto DC 618 7,850 2004 

Silvertip AC 815 9,226 2004 

Tiger AC 818 9,004 2004 

Tobago AC 859 9,627 2004 

Jubilee Extension LL 309 8,774 2005 

Mondo NW Extension LL 1 8,340 2005 

Q MC 961 7,925 2005 

Stones WR 508 9,556 2005 

AC = Alaminos Canyon 

AT = Atwater Valley 

DC = DeSoto Canyon 

LL = Lloyd Ridge 

MC = Mississippi Canyon 

WR = Walker Ridge 

Piston cores have sampled about 100 sites that contain both thermogenic and biogenic gas hydrates. 

Thermogenic gas hydrates are known only in the GOM, whereas biogenic gas hydrates are found in many 

other marine settings around the world. The gas contained in thermogenic gas hydrates is derived from 

deeply buried, organic-rich sediments, or existing gas reservoirs, and has migrated upward into the zone 

of hydrate stability. Thermogenic hydrates contain a mixture of complex hydrocarbon gases. Biogenic 

gas hydrates contain gas generated at shallower depths by bacterial decomposition of organic matter, 

yielding primarily methane gas. Gas-hydrate mounds and associated chemosynthetic communities, 

commonly at the edges of deepwater mini-basins, have been observed and sampled by research 

submersibles at many sites in the GOM. 
14 

Many questions remain about the distribution, concentration, reservoir properties, and stability of 

hydrates. Conventional drilling operations do not allow sampling of the upper 3,000 ft (914 m) of 

sediment (where hydrates occur). Although conventional 3-D exploration and high-resolution seismic 

data are not specifically designed to detect hydrate deposits, interpretive techniques have been used to 

delineate possible hydrates. 

To gather hydrate data for the Gulf of Mexico, a Joint Industry Project of MMS and seven oil and service 

companies, largely funded by the Department of Energy (DOE), conducted a 35-day expedition in the 

spring of 2005 to drill, log, and core sediments containing gas hydrates. Five separate boreholes were 

drilled near seafloor hydrate mounds in Atwater Valley and Keathley Canyon to depths as great as 1,509 

ft (460 m). Two holes were cored on top a hydrate mound in Atwater Valley to a depth of 98 ft (30 m). 

Downhole log data and pressure cores revealed evidence of gas hydrates in all boreholes at levels 

approximating those predicted by pre-cruise seismic analysis. Sediment at both locations was fine 

grained with stratigraphically controlled hydrate-bearing intervals in Atwater Valley and steeply dipping, 

hydrate-filled fractures in Keathley Canyon. Because economically significant quantities of gas hydrate 

are probably limited to sandy reservoirs, a second hydrate drilling initiative with a multi-well program is 

planned for 2007. MMS will again play a major role on the site-selection team by using information from 

the sand studies done in the initial inventory of recoverable gas hydrates for the National Oil and Gas 

Assessment Program. 

LEASING ACTIVITY

The DWRRA encouraged extensive leasing in the deepwater GOM. Figure 9 shows the recent history of 

deepwater leasing. Activity slowly increased from 1992 through 1995, but immediately after the 

DWRRA was enacted, deepwater leasing activity exploded. Other factors also contributed to this 

activity, including improved 3-D seismic data coverage, key deepwater discoveries, the recognition of 

high deepwater production rates, and the evolution of deepwater development technologies. 

With the passage of the Energy Policy Act of 2005, lease terms for deepwater royalty relief were 

changed. The Act eliminated the existing 1,600-m or deeper water-depth category for royalty relief and 

established two new royalty suspension categories: 1,600- to 2,000-m and greater than 2,000-m water 

depth. Sale 196 (Western GOM Planning Area, August 17, 2005) was the first lease offering to 

implement these “new” royalty relief provisions. 

Table 3 shows the approximate number of active leases for certain water-depth ranges. The geographic 

distribution of active leases in the GOM is shown in figure 10. The limited number of active leases in the 

eastern GOM is related to leasing restrictions. In 2001 and 2003, sales were held offshore of Alabama, 

approximately 100 miles from the coastline, which added 109 active leases. Appendix B provides a 

chronological listing of all Gulf of Mexico lease offerings arranged by sale number, location, and date. 

Table 3 

Number of Active Leases by Water-Depth Interval 

Number of Water Depth 

Active Leases* ft m 

3,826 <1,000 <305 

173 1,000-1,499 305-457 

1,960 1,500-4,999 457-1,524 

1,516 5,000-7,499 1,524-2,286 

746 >7,500 >2,286 

*as of December 31, 2005 
15















	







	






 

 

Figure 8. Location of known gas hydrates in the Gulf of Mexico. 
16 

Figure 9. Deepwater leases issued in the Gulf of Mexico. 
17 

Figure 9. Deepwater leases issued in the Gulf of Mexico (continued). 
18

	

	







 	






	

	





  



 

 	
 



	





	
  	
 	
 	

 
   

  

 	










 


Figure 10. Active leases in the Gulf of Mexico. 
19 

OCEAN CURRENT MONITORING

The most energetic currents in the Gulf of Mexico are created by the Loop Current, which moves from 

the Caribbean Sea into the eastern part of the Gulf and exits between southern Florida and Cuba 

(figure 11). It affects the ocean from the surface to approximately 3,000-ft (914-m) water depth with 

varying speeds. Currents as high as 4 knots (kn) have been observed from the surface to 1,000-ft (305-m) 

water depths. These upper currents then taper off between 1,000- and 3,000-ft (305- and 914-m) depths. 

The loop current path may vary by hundreds of miles while the flow direction generally remains constant. 

Once it reaches its most northward position, a portion may break off and form an eddy current, a mass of 

clockwise-rotating water that traverses westward until it dissipates off the western coast of the Gulf. 

Ocean currents disrupt offshore operations and reduce the working life of certain equipment. In an effort 

to understand currents in the Gulf of Mexico and to provide information for forecasting, hindcasting, and 

fatigue damage, the MMS created a program to monitor currents from all deepwater rigs and floating 

platforms. In 2005, the MMS issued Notice to Lessees and Operators (NTL) 2005-G05, “Deepwater 

Ocean Current Monitoring on Floating Facilities.” This program requires operators to submit data in a 

standardized format to a publicly accessible website. This information is displayed real-time and can be 

downloaded for forecasting of currents and for historic reference. 

Operators are encouraged to use the information from nearby facilities, as well as their own, for daily 

operations and for determining damage caused by severe currents. In addition, site-specific data must be 

used in the design of new floating production facilities and drilling rigs, and their ancillary equipment, 

such as steel catenary risers and mooring systems. 

The NTL specifies that Acoustic Doppler Current Profiler (ADCP) systems or similar equipment should 

be used to measure currents to at least 1,000-m (3,280-ft) water depth and that the information be sent to 

the National Data Buoy Center for display and storage. Certain considerations are made for location and 

water depth and for systems that were in place prior to the NTL. 

The MMS has used this information in investigations where ocean currents may have contributed to 

certain incidents. Industry is using the published information to substantiate computer models and to 

enhance their forecasts. Ocean currents are considered when scheduling operations such as installation 

and drilling programs to minimize downtime because of weather effects. Other studies such as long-term 

forecasting and environmental effects are being planned. 

CHALLENGES AND REWARDS

Significant challenges exist in deepwater in addition to environmental considerations. Deepwater 

operations are very expensive and often require significant amounts of time between the initial 

exploration and first production. Despite these challenges, deepwater operators often reap great rewards. 

Figure 12 shows the history of discoveries in the deepwater GOM. There was a shift toward deeper water 

over time, and the number of deepwater discoveries continues at a steady pace. (The Reserves and 

Production section of this report explains how discovery dates are assigned.) 

Figure 13 shows how major and nonmajor oil and gas companies compare in terms of deepwater project 

discoveries. In the past, major companies were responsible for the majority of discoveries and led the 

way into the deepest waters. However, the number of discoveries by nonmajor companies has surpassed 

that by major companies. In addition, nonmajor companies have made numerous recent discoveries in the 

deepest waters of the frontier. 
20 

Figure 11. Loop and eddy currents in the Gulf of Mexico (image courtesy of Johns Hopkins University). 
21

Figure 12. Deepwater discoveries in the Gulf of Mexico. 
22





































































































































































































 







































































































 





 	






	

	 
	

	 	





Figure 13. Ownership of deepwater discoveries (includes industry-announced discoveries). 
23 

In addition to the significant number of deepwater discoveries, the flow rates of deepwater wells and the 

field sizes of deepwater discoveries are often quite large. These factors are critical to the economic 

success of deepwater development. Figure 14 illustrates the estimated sizes and distributions of 

87 proved deepwater fields. In addition to their large sizes, deepwater fields have a wide geographic 

distribution and range in geologic age from Pleistocene through Paleocene. Note that only since 2001 

have reservoirs older than Miocene been encountered. 

The growing number of large deepwater fields on production requires increasing support from onshore 

service bases. Most producing deepwater fields have service bases in southeast Louisiana (figure 15). 

Pending exploration plans (EP’s) and development operations coordination documents (DOCD’s) filed 

with MMS indicate that support from southeastern Louisiana will continue to grow and that additional 

support will come from southwest Louisiana, Mississippi, and the Texas coast (figure 16). Although 

expanding along the Gulf Coast, shore-based support for deepwater operations is likely to remain 

concentrated in southeastern Louisiana. 

Figure 17 illustrates existing and potential hubs for deepwater production. For purposes of this report, 

deepwater hubs are defined as surface structures that host production from one or more subsea projects. 

These hubs represent the first location where subsea production surfaces and are the connection point to 

the existing pipeline infrastructure. Note that potential hubs are moving into deeper waters, expanding 

the infrastructure, and facilitating additional development in the ultra-deepwater frontier. 

LNG PROJECTS

Offshore liquefied natural gas (LNG) terminals may bring significant additional gas into the GOM and 

may vie for pipeline capacity with future deepwater developments. Table 4 shows proposed and/or 

licensed LNG terminals in the GOM. Port Pelican LNG terminal (slated for Vermilion 140) has been 

permitted, but the licensee has put the project on hold indefinitely. The application for the Pearl Crossing 

LNG terminal (West Cameron 220) has been withdrawn. 

Table 4 

LNG Projects Proposed or Licensed in the Gulf of Mexico 

Project Name Company Area and Block Facility Type Status 

Gulf Gateway 

Energy Bridge Excelerate Energy West Cameron 603 Submerged Turret Buoy 

commenced operations 

March 2005 

Gulf Landing 

Gulf Landing, LLC (subsidiary 

of Shell US Gas and Power, 

LLC) 

West Cameron 213 Gravity-Based 

Structures licensed June 2005 

Compass Port 

Compass Port, LLC 

(subsidiary of ConocoPhillips 

Company) 

Mobile 910 Gravity-Based 

Structures 

preliminary final EIS 

distributed 

Main Pass Energy 

Hub 

Freeport-McMoRan Energy, 

LLC Main Pass 299 New and Existing 

Structures 

DEIS and Public 

Hearings complete 

Beacon Port Beacon Port, LLC (subsidiary 

of ConocoPhillips Company) West Cameron 167 Gravity-Based Structures 

preliminary draft EIS 

complete 

Bienville Offshore 

Energy Terminal TORP Terminal LP Main Pass 258 HiLoads with SALM Buoys 

preparation of a DEIS 

underway 
24

Figure 14. Estimated volume of 87 proved deepwater fields. 
25

Figure 15. Onshore service bases for existing deepwater structures. 
26

Figure 16. Onshore service bases for pending deepwater plans. 
27

	




 

 	





 	










 
 		 


 




!

!"



















































































 

 







 







 

 



 











 







 









 





































 







 



 

 



























 









 

















  











 		 



	











	






Figure 17. Current, potential, and future hub facilities in the Gulf of Mexico. 
29 

LEASING AND ENVIRONMENT 

LEASING ACTIVITY

Until the mid-1990’s, leasing activities in the Gulf of Mexico were focused on shallow-water blocks 

located on the continental shelf (water depths of approximately 650 ft [200 m] or less). With the passage 

of the DWRRA in 1995, royalty relief incentives were established for new leases on the basis of waterdepth intervals (defined in meters). The water-depth categories depicted in figure 18 reflect the divisions 

set forth in the DWRRA. This figure shows the magnitude of the DWRRA impact, with tremendous 

deepwater leasing activity from 1996 through 1998 in water depths greater than 800 m (2,625 ft), where 

the greatest royalty relief was available. During this same period, interest in shallow-water blocks faded. 

The Gulf experienced a lull in leasing activities at all water depths in 1999. In 2000 and 2001, there was 

a rekindling of interest in blocks in the 200-m (650-ft) or less range. Some of this interest in the shelf 

blocks is likely attributable to the MMS’s royalty suspension program for deep-gas development in water 

depths less than 200 m (650 ft). 

With the passage of the Energy Policy Act of 2005, lease terms for deepwater royalty relief were 

changed. Paragraph (b) of Subtitle E, Section 345 of the Act detailed the possible royalty suspension 

volumes on the basis of water depths. The Act eliminated the existing 1,600-m or deeper water-depth 

category for royalty relief and established two new royalty suspension categories: 1,600 to 2,000-m and 

greater than 2,000-m water depth. Sale 196 (Western GOM Planning Area, August 17, 2005) was the 

first lease offering to implement these “new” royalty relief provisions. Table 5 shows the potential 

volume of hydrocarbons subject to suspension, according to the corresponding water-depth range. 

Table 5 

Deepwater Royalty Relief by Water-Depth Range 

Water-Depth Range 

(in meters) 

Royalty Suspension Volume 

Up To: (in BOE) 

400 to 800 5,000,000 

800 to 1,600 9,000,000 

1,600 to 2,000 12,000,000 

>2,000 16,000,000 

Paragraph (c) of Subtitle E, Section 345 of the Act allows the Secretary of the Interior to place limitations 

on the royalty relief granted under the provision of the Act on the basis of market price. 

From 2000 to 2003, there was a relatively steady increase in the number of leases issued in the greater 

than 800-m (2,625-ft) range. Of interest is the small peak that occurred in this range in 2001, the result of 

a lease offering (Sale 181) in a deepwater portion of the Eastern GOM. This area had not been offered for 

lease in 13 years. Leasing, operational activities, and discoveries in the easternmost portion of the Central 

GOM Planning area adjacent to the Sale 181 area spurred interest in the area. There were 95 leases issued 

in water depths 1,600-m (5,250-ft) or greater in this sale. The small peak resulted when these were added 

to the annual Central and Western GOM sales. Subsequent lease sales have occurred in the deepwater 

EGOM area, but the number of leases issued has been smaller than that for Sale 181. 

From 2001 to 2004, the number of leases issued in water depths of 200-m (650-ft) or less remained fairly 

constant; however, this water-depth interval experienced a decrease in the number of leases issued in 
30 

2005. For the greater than 800-m (2,625-ft) range, the number of leases issued from 2002 to 2005 has 

remained relatively constant. 

The data shown in figure 19 are a subset of figure 18 and include the new royalty-relief water-depth 

categories implemented by the Energy Policy Act of 2005. There has been a 40-percent increase in lease 

activity in the greater than 2,000-m (6,560-ft) water-depth category since 2003. 

BIDDING AND LEASING TRENDS

Figure 20 was derived from the data in figure 18 but displays the deepwater categories used elsewhere in 

this report (shallow-water data are excluded from this figure). These deepwater data show the rapid 

increase in leasing activity that began in 1995 and continued through 1998. Leasing increased 

sequentially in deeper water depths with time. Lease activity in the 1,500 to 4,999-ft (457 to 1,524-m) 

range began its ascent in 1995. The following year there was a rise in leasing activity in the 5,000 to 

7,500-ft (1,524 to 2,286-m) range in 1996. This range actually outpaced the 1,500 to 4,999-ft (457 to 

1,524-m) interval in 1997. Note that the peak in leasing for the greater than 7,500 ft (>2,286 m) range 

occurred a year later in 1998. The 1,500 to 4,999-ft (457 to 1,524-m) and 5,000 to 7,499-ft (1,524 to 

2,286-m) ranges decreased in 1998. Leasing activity plummeted in 1999, nearing 1994 levels. From 

1999 to 2003, there was a steady increase in leases awarded in the 1,500 to 4,999-ft (457 to 1,524-m) 

range. The number of awarded leases has remained relatively constant since. The 5,000 to 7,499-ft 

(1,524 to 2,286-m) interval saw a similar rise; however, this range has experienced a decline from 2003 to 

2005. With the exception of 2001, the greater than 7,500-ft (2,286-m) range remained level from 1999 

through 2003. This was followed by a three-fold increase in leasing from 2003 to 2005. 174 261 466499 627 527 265 168 325 452 421 474

465

331

99

16

45

62

41

35

1414

33

35

15

51

25

15

31

27

84

112

105

57

16

29

75

6868

57

70

12

36

51

208

709

1105

772

135

185

382

281

319

330

318

0

200

400

600

800

1,000

1,200

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year of Lease Sale

Number of Leases Issued

< 200 m

200 - 400 m

400 - 800 m

> 800 m

DWRRA post-DWRRA

Figure 18. Number of leases issued each year, subdivided by DWRRA water-depth categories. 
31 

25

233

404 436

44 46

142

34

87 88 124 38

159

283

108

26 39

44

110

77 60

40

36 38

145

317

419

65

100

196

137

169 168 154

7 2

6

228

10

0

200

400

600

800

1,000

1,200

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year of Lease Sale

Number of Leases Issued

800 - 1,600 m

1,600 - 2,000 m

> 2,000 m

DWRRA post-DWRRA includes EGOM Sale 181

Figure 19. Number of leases issued each year in depths greater than 800 m, subdivided by waterdepth categories specified in the Energy Policy Act of 2005. 

4

24 3

5

66

14

56

15

1

26

209

65 9

50

376

304

121

25

466

496

237

24

249

255

318

6

75

48

27

12

120

71

19

24

250

92

108

23

182

142 18

14

217

154

23

30

205

115

46

19

211

89

80

0

100

200

300

400

500

600

Number of Leases Bid On 

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Lease Sale Year

1,000-1,499 ft

1,500-4,999 ft

5,000-7,499 ft 

>7,500 ft

DWRRA post-DWRRA

Figure 20. Number of leases bid on for each deepwater interval. 
32 

LEASE OWNERSHIP

A handful of major oil and gas companies blazed the trail into deepwater in the 1980’s and early 1990’s. 

In this report, we define major companies to include BP, ChevronTexaco, ExxonMobil, and Shell. 

Grouping of these four entities does not indicate a regulatory conclusion or an analysis of production size. 

It is merely a convenient category for the purpose of comparison. Figure 21 illustrates the relative 

leaseholding positions of majors versus nonmajors (as of December 31, 2005). Nonmajors began 

acquiring significant leaseholdings in the mid-1990’s, a trend that continued through 2005. 

Note also that, according to public records, Chevron and Unocal merged in August 2005. To date, papers 

to that effect have not been filed with MMS; therefore, the companies are considered herein as separate 

entities. 

FUTURE DEEPWATER LEASE ACTIVITY

There are two remaining lease sales scheduled, in addition to Sale 198 (CGOM), which was held March 

15, 2006, under the five-year program for 2002 to 2007. They include Sale 200 (WGOM) in 2006 and 

Sale 201 (CGOM) in 2007. The MMS is developing the five-year program for 2007 to 2012. The new 

program continues to schedule annual area-wide lease sales for the CGOM and WGOM Planning Areas 

for a total of 11 lease offerings. The new program for 2007 to 2012 reconfigures some planning areas to 

follow the new administrative lines. As such, some of the areas formerly included in the Eastern and 

Western Planning Areas are now scheduled to become part of the CGOM Planning Area. 

There were a large number of deepwater leases issued from 1996 to 1998. Many of these leases are 

coming to the end of their primary lease term (most had 10-year lease terms). Challenges in the 

deepwater environment have made it difficult for the industry to test many of these leases. In recognition 

of this problem, the MMS recently published a Notice to Lessees and Operators (NTL No. 2006-G02) 

entitled, “Suspension of Operations Based on Rig Delays, Lack of Rig Availability and Procurement of 

Long Lead Equipment.” The purpose of the NTL is to “...to provide guidance to our existing authority 

for approving requests for lease or unit Suspension of Operations (SOO) based on rig delays and to 

implement a temporary policy for granting SOO’s based on a lack of rig availability and for unanticipated 

time frames needed to secure long lead equipment such as high-pressure/temperature tubulars and 

wellheads.” Operators must meet established criteria listed within the NTL to request a suspension 

(Appendix C). 

Lessees/operators who have conducted certain activities on a lease and have met the criteria established 

for a Suspension of Production (SOP) may request a suspension to maintain their lease until activities 

detailed in their SOP are accomplished. The key to the SOO and SOP provisions is to allow operators 

who have diligently attempted to explore and develop their lease(s) sufficient time to do so when 

circumstances beyond their control require more time than is allowed in their lease term. For example, 

certain high-pressure/high-temperature conditions within a well require equipment that requires a long 

lead time. 

The overall effect of the NTL is the potential retention of leased blocks beyond their projected expiration 

date. Fewer deepwater blocks will be returned to the inventory for future lease sale offering or available 

for “farm outs” to other companies who are hoping to expand their interest in deepwater. 

Figure 22 shows leases that may expire in the coming years, assuming each lease expires at the end of its 

primary lease term (without a lease-term extension). Note that lease terms vary according to water depth. 

Primary lease terms are five years for blocks in less than 400 m (1,312 ft), eight years for blocks in 400 to 

799 m (1,312 to 2,622 ft), and ten years for blocks in 800 m (2,625 ft) or greater. Therefore, in the 

absence of primary lease-term extensions, all active shallow-water leases will expire before 2012 

(explaining the absence of expiring shallow-water leases in certain frames of figure 22). 
33

 



		


				 


	

	
	
 	
 
	
	



	 

  

  

"!

Figure 21. Ownership of deepwater leases. 
34 

Figure 22. Anticipated lease expirations in the Gulf of Mexico. 
35 

Figure 22. Anticipated lease expirations in the Gulf of Mexico (continued). 

ENVIRONMENTAL ACTIVITY

The extensive activity in the deepwater GOM requires thorough scientific knowledge and careful 

environmental considerations. The Environmental Studies Program (ESP), initiated in 1973, gathers and 

synthesizes environmental, social, and economic information concerning offshore oil and gas activities. 

The ESP expanded its focus to address particular issues as industry moved into deepwater. For example, 

studies were begun to evaluate the sensitivity of chemosynthetic ecosystems. Refer to Appendix D for a 

listing of selected deepwater environmental studies. 

A biologically based grid system was developed as part of a comprehensive strategy to address deepwater 

issues. The grid system divided the Gulf into 17 areas or "grids" of biological similarity (figure 23). 

Under this strategy, the MMS will prepare a programmatic environmental assessment (PEA) to address a 

proposed development project within each of the grids. These grid PEA’s are comprehensive in terms of 

the impact-producing factors and in terms of the environmental and socioeconomic resources described 

and analyzed for the entire grid. Other information on publicly announced projects within the grid is 

discussed, as well as any potential effects expected from their future developmental activities. Projects 

selected for the grid PEA’s are representative of the types of development expected for the grid. For 
36

Figure 23. Grid EA status. 
37 

example, a good candidate for a grid PEA would be a proposed development of a new surface structure 

that might serve as a "hub" for future development within the grid. 

Once a grid PEA has been completed, it will serve as a reference document to implement the "tiering" 

concept detailed in the implementing regulations of the National Environmental Policy Act (NEPA). 

Future environmental evaluations may reference appropriate sections from the PEA to reduce duplication 

of issues and effects addressed in the grid NEPA document. This will allow the subsequent 

environmental analyses to focus on specific issues and effects related to the proposals. 

Table 6 below shows the status of the grid PEA’s. 

Table 6 

Completed Grid PEA’s Within the Central and Western Planning Areas of the Gulf of Mexico 

Grid Project Name Company Plan Area and Blocks 

3 Gunnison Kerr-McGee N-7625 GB 667, 668, & 669 

4 Nansen Kerr-McGee N-7045 EB 602 & 646 

7 Magnolia Conoco N-7506 GB 783 & 784 

10 Holstein BP N-7216 GC 644 & 645 

12 Medusa Murphy N-7269 MC 538 & 582 

13 Marco Polo Anadarko N-7753 GC 608 

15 Matterhorn TotalFinaElf N-7249 MC 243 

16 Thunder Horse BP N-7469 MC 775-778 & 819-822 

EB = East Breaks 

GB = Garden Banks 

GC = Green Canyon 

MC = Mississippi Canyon 

To continue implementation of its deepwater strategy, MMS issued Notice to Lessees and Operators 

(NTL) No. 2003-G03, “Remotely Operated Vehicle Surveys in Deepwater,” with an effective date of 

January 23, 2003. The NTL requirements apply to activities in water depths greater than 400 m (1,312 ft) 

in the Central and Western Planning Areas of the GOM. Operators submit a remotely operated vehicle 

(ROV) survey plan as an integral part of an Exploration Plan (EP) or a Development Operations 

Coordination Document (DOCD) that proposes a surface structure in one of the 17 grid areas. The MMS 

will notify an operator in the EP or DOCD approval letter if the operator needs to conduct the ROV 

survey. The decision to require the survey is based on whether or not the grid area that contains the 

proposed activities has already received adequate ROV-survey coverage. Figure 24 shows the location of 

existing ROV surveys. 

Exploration and development activities in deepwater may have localized impact on benthic communities. 

A description of these potential impacts is available in Gulf of Mexico Deepwater Operations and 

Activities: Environmental Assessment (USDOI, MMS, 2000). The MMS believes that sensitive benthic 

communities such as chemosynthetic communities are protected by the existing review process, relying 

on NTL’s and mitigative measures that require avoidance of sensitive communities. 

The ROV monitoring surveys are intended to verify the effectiveness of mitigative measures and to 

ensure that previously unknown, high-value benthic communities do not exist in the vicinity of proposed 

activities. New information could lead to changes in the review process and in the mitigative measures 

required. 
38 

The new generation work-class ROV (WROV) is rated to 10,000 ft (3,049 m) and adaptable for depths to 

19,500 ft (5,945 m), which will allow it to work in deep and ultra-deepwater areas of the GOM. Canyon 

Offshore recently announced a record-setting work dive to 9,024 ft (2,751 m) in Lloyd Ridge Block 399 

with its Quest electric WROV. The dive, conducted in water depths of 9,000 ft (2,744 m) and deeper, 

lasted 30 hours. The WROV was deployed to perform pre-lay route surveys for 8-inch and 10-inch 

flowlines and to conduct array integrity checks. 
39









 





 

 









 

 





 



 























 









 



   















 

















  











 











 



 

























 

  











 



 

 







		 







	
 
	
 
	






 

	








		 



 





 





	




	

 



 
 
  *  

*  

	

 +
(
 &) &
%  
% 

Figure 24. ROV surveys including known chemosynthetic communities. 
41 

DRILLING AND DEVELOPMENT 

Deepwater drilling occurs from mobile offshore drilling units (MODU’s), such as semisubmersible units 

or drillships (figures 25 and 26), and from rigs located on combination production/drilling platforms. 

Numerous deepwater prospects are waiting to be drilled, and many may remain undrilled as the primary 

lease terms expire because of the limited number of rigs available for deepwater drilling in the GOM. In 

addition, the increased depths to which some operators are increasingly drilling cause rigs to be under 

contract for longer periods. Industry responded to the limited rig availability by ordering 11 

semisubmersibles and two drillships in 2005 (Gulf of Mexico Newsletter, January 2, 2006). Chevron has 

entered a drilling contract with Transocean Inc. that will initiate the construction of a new state-of-the-art 

drillship that will be dedicated exclusively to Chevron for five years. The new drillship, to be named 

Discoverer Clear Leader, is expected to be completed and in service by January 2009. The Discoverer 

Clear Leader will be a dynamically positioned, double-hull drillship that will feature dual-activity 

technology that utilizes two drilling systems in a single derrick. The drillship will be designed to drill 

wells up to 40,000 ft (12,195 m) in depth and in water depths up to 12,000 ft (3,658 m). 

Figure 27 depicts deepwater rigs operating in the GOM from 1992 through 2005.1

 There was a steady 

increase in the average number of rigs operating from 1992 to a peak in 2001. The average number of 

rigs operating in the GOM decreased from 2002 through 2004 but increased in 2005. 

Figure 28 shows the number of deepwater MODU’s by water-depth categories in the GOM and 

worldwide. Approximately 32 percent of the world’s fleet of deepwater drilling rigs is committed to 

GOM service. The pie chart within figure 28 shows the distribution of deepwater rigs by major operating 

area. Most, if not all, of the deepwater-capable drilling rigs are under long-term contractual 

arrangements. The reader is cautioned not to draw conclusions from the rig count differences between 

figures 27 and 28. As mentioned above, figure 27 includes platform rigs in addition to MODU’s; figure 

28 addresses MODU’s only. Further, not all MODU’s in figure 28 are operating at any given time, and 

upgrades to MODU’s that increase their water-depth capability will alter the rig counts shown; 

consequently, year-to-year comparisons may not be valid. 

DRILLING ACTIVITY

The number of deepwater wells drilled generally increased from 1992 through 2001; however, the activity 

has declined in three of the last four years. Only original boreholes and sidetracks are included in the well 

counts used in this report. Wells defined as “by-passes” are specifically excluded. A “by-pass” is a 

section of well that does not seek a new objective; it is intended to drill around a section of the wellbore 

made unusable by stuck pipe or equipment left in the wellbore. Figure 29 shows that most of the drilling 

has occurred in the 1,500- to 4,999-ft (457- to 1,524-m) water-depth range. In the last five years, twelve 

wells have been drilled in water depths exceeding 9,000 ft (2,744 m), and in December 2003, the first 

well in water depths over 10,000 ft (3,050 m) was drilled. 

During three of the last four years, industry has experienced significant disruptions caused by major 

hurricane activity in the Gulf of Mexico. Within a six-month period in 2005, eight hurricanes disrupted 

offshore OCS activities. Figures 30 and 31 attempt to capture the possible effects on drilling caused by 

storm activity. Figure 30 depicts all deepwater wells drilled during the months of January through June, 

while figure 31 shows all deepwater wells drilled during July through December for 1992 through 2005. 

The data show a much steeper decline in drilling since 2001 during the last six months of the year. This 

is caused in part by the hurricane season, which runs from June 1st through November 30th. The last two 

 

1

 It is important to note that the rig count includes platform rigs operating on deepwater production facilities in 

addition to the MODU’s. About one-third of all rigs are platform rigs. The numbers do not distinguish between rigs 

drilling and those in service for completion and workover operations. 
42 

Figure 25. The Deepwater Horizon, a dynamically positioned, semisubmersible drilling unit 

(photo courtesy of Transocean). 

Figure 26. The Discoverer Enterprise, a double-hulled, dynamically positioned drillship (photo 

courtesy of Transocean). 
43 

3

6

11

14

18

26

28 28

33

41

36

30

26

30

0

5

10

15

20

25

30

35

40

45

50

Average Number of Deepwater Rigs Operating

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

Figure 27. Average number of rigs operating in the deepwater GOM. 

1

14 13

60

16

35

14

31

0

10

20

30

40

50

60

Number of Rigs

1,000 - 1,499 1,500 - 4,999 5,000 - 7,499 > 7,500

Maximum Water Depth Capability (ft)

GOM rigs

All rigs

Other, 29

GOM, 41

Africa, 25

Brazil, 19

North Sea, 

12

Figure 28. Approximate number of deepwater rigs (GOM and worldwide) subdivided 

according to their maximum water-depth capabilities. Inset shows the number of 

deepwater rigs in various locations. 
44

2110

1

2614

1

1845

1

2556

3

2475

6

1

32

132

12

33

123

10

1

15

119

35

30

144

25

9

25

127

53

6

20

126

3510

20922213

0

50

100150200250

Number of Wells Spudded

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 

Year

> 7,500 ft5,000 - 7,499 ft1,500 - 4,999 ft1,000 - 1,499 ft

32

41

64

84

106

176

167 169

208 211

191

147 

Figure 29. All deepwater wells drilled in the Gulf of Mexico, subdivided by water depth. 
45 

6

9 17

6

1

8

24

11

19

1

11

39

1

13

63

2

13

66

7

7

53

12

16

69

10

4

13

61

27

4

7

71

20

3

7

51

7

7

11

29

31

11

5

54

8

9

0

20

40

60

80

100

120

Number of Wells Spudded (January through June)

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

January - June

Figure 30. All deepwater wells drilled from January through June in the Gulf of Mexico by 

water depth. 

15

1

1

9

8

10

21

1

14

37

2

13

36

6

19

69

10

20

57

3

1

8

66

23

14

75

15

5

12

66

26

2

13

54

15

7

13

41

15

6

4

38

18

6

1

35

5

3

0

20

40

60

80

100

120

Number of Wells Spudded (July through December)

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

Hurricanes Katrina and Rita (August/September)

Hurricane Ivan (September)

Hurricanes Isadore and Lili 

(September/October)

Hurricanes Georges and Earl 

(September)

July - December

Figure 31. All deepwater wells drilled from July through December in the Gulf of Mexico by 

water depth. 
46 

years were particularly active with several major hurricanes entering the GOM, including Hurricanes 

Ivan, Katrina, and Rita. 

Figures 32 and 33 break down the annual deepwater well counts (shown in Figure 29) into exploratory 

and development wells, respectively. This report uses the designation of exploratory and development 

wells provided by the operators. The data reflect the variations among operators in classifying wells as 

either development or exploratory. After decreasing in 2002 and 2003, the number of exploratory wells 

drilled in 2004 increased, followed by a slight decrease in 2005. Exploratory drilling in the 1,500- to 

4,999-ft (457- to 1,524-m) water-depth range remained the same from 2002 through 2004 but increased in 

2005. There has been a decrease in the number of development wells drilled since 2002. Possible 

reasons for the decrease may be the method by which wells are categorized in this report (exploratory 

versus development), the retention of exploratory wells for production purposes, and the lag from 

exploration to first production. The complexity of the deepest water developments may also be a factor, 

requiring operators to spend more time in planning and design. Most development drilling in 2005 was in 

the 1,500- to 4,999-ft (457- to 1,524-m) water-depth range. 

Figure 34 illustrates the geographic distribution of deepwater exploratory wells. Note the progression 

into deeper water through time. Figure 35 depicts the locations of deepwater development wells. Once 

again, the data reveal a general increase in activity as well as a trend toward increasing water depth with 

time. 

One indicator that MMS has found useful in projecting activity levels is the number of plans received. 

Although the order of plan submission and drilling activities can vary with projects, operators generally 

proceed as follows: 

• file an Exploration Plan (EP), 

• drill exploratory wells, 

• file a Conceptual Deep Water Operations Plan (DWOP), 

• file a Development Operations Coordination Document (DOCD), 

• file a DWOP, 

• drill development wells, then 

• begin production. 

30 CFR 250 and 282: Oil and Gas and Sulfur Operations in the Outer Continental Shelf – Plans and 

Information; Final Rule was completed on August 30, 2005. These changes will be reflected in the 

submittal process and requirements for plans received after January 1, 2006, but were not taken into 

account for this report. 

Figure 36 shows the number of deepwater EP’s, deepwater DOCD’s, and DWOP’s received each year 

since 1992 (DWOP’s were not required until 1995). The count of EP’s, DOCD’s, and DWOP’s includes 

only the initial plans. Some shallow-water activities are included in the DWOP data because DWOP’s 

must be filed and approved for developments in greater than 1,000-ft (305 m) water depths and for all 

subsea developments regardless of water depth. The discussion of subsea wells later in this report will 

address the significance of shallow-water subsea tiebacks—the effective use of deepwater technologies in 

marginal developments. 

There was a marked increase in EP’s, DOCD’s, and DWOP’s beginning in 1996. After reaching a peak 

of 92 in 1999, the number of submittals of EP’s decreased and then hovered near 70 per year 
47 

1

3

1

3

14

6

38

1

8

38

2

7

50

6

1

17

81

9

20

87

9

10

61

29

8

67

17

8

5

74

30

5

10

44

19

10

7

43

13

11

10

44

20

16

4

64

13

11

0

20

40

60

80

100

120

Number of Exploratory Wells Spudded

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

5

17

45

48

64

107

116

100 100

114

83

74

90 92

Figure 32. All deepwater exploratory wells drilled in the Gulf of Mexico by water depth. 

20

7

23

1

12

7

17

18

1

17

25

15

51

3

13

36

1

1

5

58

6

22

77

8

1

20

53

23

1

10

82

16

13

49

9

2

5

24

29

1

2

24

1

0

20

40

60

80

100

120

Number of Development Wells Spudded

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

27

24

19

36

42

69

51

69

108

97

108

73

59

27

Figure 33. All deepwater development wells drilled in the Gulf of Mexico by water depth. 
48 

Figure 34. Deepwater exploratory wells drilled in the Gulf of Mexico. 
49 

Figure 35. Deepwater development wells drilled in the Gulf of Mexico. 
50 

13

2

13

3

20

2

19

4

5

29

8

19

69

6

30

80

9

16

92

7

18

76

12

28

67

18

36

69

23

28

75

10

28

51

13

25

69

28

34

0

10

20

30

40

50

60

70

80

90

100

Number of Plans Received

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

Deepwater EP*

Deepwater DOCD*

DWOP*

*initial submissions only

Figure 36. Deepwater EP’s, DOCD’s, and DWOP’s received in the Gulf of Mexico since 1992. 

with the exception of 2004. The number of DOCD submittals reached a high of 28 in 2005. There was 

an increase in the number of initial DWOP’s submitted from 2004 to 2005. 

Until recently, there had been a gradual increase of drilling depth (as measured in true vertical depth 

[TVD]). Beginning in 1996, the maximum drilling depth increased rapidly, reaching depths below 

30,000 ft (9,144 m) in 2002. The Transocean Discoverer Spirit drilled the deepest well in the GOM to 

date, Chevron/Unocal’s Knotty Head discovery in Green Canyon Block 512, reaching a TVD of 34,157 ft 

(10,411 m) in December 2005. The recent dramatic increase in TVD may be attributed to several factors, 

including enhanced rig capabilities, deeper exploration targets, and the general trend toward greater water 

depths. Chevron holds another world record – drilling in 10,011 ft (3,051 m) of water at its Toledo 

prospect in Alaminos Canyon Block 951 in November 2003. 

HIGH PRESSURE, HIGH TEMPERATURE 

High-pressure, high-temperature (HPHT) development is the greatest technological and regulatory 

challenge to the oil and gas industry today. The basic building blocks of structural integrity are being 

challenged. Metals and elastomers that have been in use for many years now face unique environmental 

conditions. MMS is working with industry to evaluate the risks and set limits to mitigate these potential 

hazards. MMS is also sponsoring research and participating in internal and industry-related conferences 

to stay at the forefront of new technology and is actively involved in developing options that will best 

promote human safety and environmental integrity. Figures 37 and 38 demonstrate that MMS and 

industry are already exploring the HPHT condition and illustrate the importance of developing safe, 

reliable methods of drilling and producing under these harsh conditions. The figures show that, as 

deepwater wells are drilled to greater and greater depths, they begin to encounter the same HPHT 

conditions that shallow-water wells see at shallower drilling depths. HPHT compounds the technological 
51 

0

5,000

10,000

15,000

20,000

25,000

30,000

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000

Total Vertical Depth (ft)

Estimated Bottomhole Pressure (psi)

< 1,000' water depth

> 1,000' water depth

Figure 37. Estimated bottomhole pressure (psi) versus total vertical depth. 

0

50

100

150

200

250

300

350

400

450

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000

Total Vertical Depth (ft)

Bottomhole Temperature (degrees F)

< 1,000' water depth

> 1,000' water depth

Figure 38. Bottomhole temperature (oF) versus total vertical depth. 
52 

challenges faced in deepwater exploration and especially in deepwater completion and production. 

Consequently, there is tremendous potential for growth and development in the HPHT area. 

DEVELOPMENT SYSTEMS

Development strategies vary for deepwater, depending on reserve size, proximity to infrastructure, 

operating considerations (such as well interventions), economic considerations, and an operator’s interest 

in establishing a production hub for the area. Figure 39 shows the different systems that can be used to 

develop deepwater discoveries. Table 7 lists the systems that have begun production. Fixed platforms 

(e.g., Bullwinkle) have economic water-depth limits of about 2,000 ft (610 m). Compliant towers (e.g., 

Petronius) may be considered for water depths of approximately 1,000 to 2,000 ft (305 to 610 m). 

Tension-leg platforms (TLP’s) (e.g., Brutus, Magnolia, and Marco Polo) are frequently used in 1,000- to 

5,000-ft (305- to 1,524-m) water depths. Spars (e.g., Genesis and Red Hawk), semisubmersible 

production units (e.g., Na Kika), and floating production, storage, and offloading (FPSO) systems (none 

in GOM) may be used in water depths ranging up to and beyond 10,000 ft (3,048 m). Figure 40 shows 

three of these development systems: a TLP, a semisubmersible, and a spar. 

Fixed Platform 

A fixed platform consists of a welded tubular steel jacket, deck, and surface facility. The jacket and deck 

make up the foundation for the surface facilities. The jacket is secured by piles driven into the seafloor. 

The height of the platform is dictated by the water depth at the intended location. Once the jacket is 

secured and a deck installed, additional modules are added for drilling, production, and crew operations. 

Large barge-mounted cranes are used in positioning and securing the jacket and the installation of the 

topside modules. Economic considerations hinder development of fixed (rigid) platforms in water depths 

greater than 2,000 ft (610 m). 

Compliant Tower 

A compliant tower consists of a narrow tower and a piled foundation. Unlike a fixed platform, a 

compliant tower has greater flexibility and can withstand large lateral forces by sustaining significant 

lateral deflections. It is usually deployed in water depths between 1,000 ft (305 m) and 2,000 ft (610 m). 

Tension-Leg Platform 

A tension-leg platform (TLP) is a compliant structural system vertically moored and uses buoyant 

components to maintain tension in the mooring system. ConocoPhillips successfully installed the deepest 

TLP in the world at Magnolia (GB 783) in December 2004 in 4,674 ft (1,425 m) of water. 

Semisubmersible Production Unit 

A semisubmersible production platform is a floating system that may have drilling capabilities. It 

comprises the following major components: pontoons, columns, and a large deck. The pontoons and 

columns provide buoyancy to the system. Production equipment, living quarters, and storage space are 

assembled on the deck. Semisubmersibles are permanently moored, using various anchoring techniques, 

and can be operated in a wide range of water depths. 

The world’s largest semisubmersible production unit, the 59,500-ton Thunder Horse production, drilling, 

and quarters (PDQ) unit, arrived in the GOM in 2004 from Korea. The topside modules, fabricated in 

Morgan City, Louisiana, were installed in Ingleside, Texas. The sheer size of the Thunder Horse project 

has garnered worldwide interest. The distance from the base of the hull to top of the drill rig is just over 

450 ft (137 m). The immense deck area is approximately three acres in area. The Thunder Horse unit 

was nearly four years in the making and will develop the largest discovery ever made in the GOM. When 

fully operational, the unit will be capable of producing an astounding 250 MBOPD and 200 MMCFPD. 

The installation of Thunder Horse (MC 778) was delayed by Hurricane Dennis in 2005 and is now slated 

for 2006. 
53 

The semisubmersible at Atlantis is scheduled to be moored in the fourth quarter of 2006 in Green Canyon 

787 in a record water depth of 7,074 ft (2,156 m). Atlantis is the second largest semisubmersible in the 

world, smaller only than Thunder Horse. The Atlantis mooring system includes the longest continuous 

wire mooring ropes ever built. Twelve large steel canisters, called suction piles, are embedded in the 

ocean floor to anchor the platform in place. Part of the chain used in this mooring system is the largest of 

its type in the world. 

ATP Oil & Gas is planning to upgrade the Rowan Midland semisubmersible drilling rig rather than build 

a new floating production facility to develop its Gomez field (MC 711). The Rowan Midland will be 

moored on location as a production facility in an effort to minimize costs and make development more 

economical. 

The Independence Hub, currently under construction, will be a state-of-the-art 105-foot, deep-draft, 

semisubmersible platform with a two-level production deck to be located in Mississippi Canyon Block 

920. Details on the Independence Hub semisubmersible are included later in this section. 

Spar 

A spar is a vessel with a circular cross-section that sits vertically in the water and is supported by 

buoyancy chambers (hard tanks) at the top, a flooded mid-section structure hanging from the hard tanks, 

and a stabilizing keel section at the bottom. A spar is held in place by a catenary mooring system, 

providing lateral stability. Currently, there are three competing versions of spars used in the GOM: 

classic spar, truss spar, and cell spar (figure 41). Some unique features of a spar include 

• favorable motion characteristics compared with other floating systems, 

• stability (the center of buoyancy is above the center of gravity), 

• cost insensitivity to water depth, and 

• water-depth capability to 10,000 ft (3,048 m) and beyond. 

The first generation of spar design is the classic spar. It is made up of one cylindrical hull that extends to 

the bottom of the structure and surrounds a center opening. This opening allows the wellhead to be on the 

platform and permits drilling and production operations. Approximately 90 percent of the classic spar’s 

hull is underwater. The first classic spar was installed in 1996 in 1,935 ft (590 m) of water in the Neptune 

field (Viosca Knoll). Other examples of a classic spar are Genesis and Hoover-Diana. 

The second generation of spar design is the truss spar. In this design, a truss structure (similar to the 

space frames used in conventional fixed platforms) replaces the lower portion of the cylindrical hull used 

in the classic spar. The truss section is lighter than the equivalent cylindrical section of the classic design, 

providing the following advantages: 

• construction costs are lower than a classic spar of similar size, 

• width of the center opening can be increased to accommodate additional wells, and 

• topside equipment can be expanded to handle additional production. 

In 2001, the first truss spar was installed over the Nansen field in 3,680 ft (1,122 m) of water. Four 

deepwater projects began production in 2004 by using spar development systems in the GOM: Front 

Runner (GC 338/339), Devil’s Tower (MC 773), Red Hawk (GB 877), and Holstein (GC 645). Mad Dog 

(GC 782) went on production in 2005, followed by Constitution (GC 680) in early 2006, using truss spar 

development systems. 

The world’s deepest dry-tree spar was installed in 2004 at Devil’s Tower in 5,610 ft (1,710 m) of water. 

It is designed to produce as much as 60 MBOPD and 110 MMCFPD. BP began production from the 
54 

world’s largest spar at Holstein in December 2004. Holstein has a hull diameter of 149 ft (45.5 m) and 

slot dimensions of 75 ft by 75 ft (22.9 m x 22.9 m). The hull diameter is twice that of Neptune, the first 

spar installed in the GOM. Holstein is expected to produce more than 100 MBOPD and 90 MMCFPD. 

The third generation of spar design is the cell spar. The cell spar’s hull is made up of several identically 

sized cylinders surrounding a center cylinder. The main advantages of the cell-spar design are reduced 

fabrication and transportation costs. The tank of a classic or truss spar requires specialized shipyard 

fabrication (large-diameter, steel-plate rolling machines). To date, all classic and truss spars have been 

constructed in European and Far East shipyards and require transport to the GOM. In contrast, each 

cylinder of the cell spar, being of a smaller diameter, can be fabricated using rolling machines that are 

readily available in most U.S. shipyards. Once fabricated, the cylinders are then lined up and welded 

together. This entire process can be done in the United States, increasing the number of contractors 

available for bidding purposes and reducing transportation costs. The main disadvantage is that the cell 

spar has no center opening for surface wellheads, so only subsea well production is possible. 

In July 2004, Kerr-McGee began production from the world’s first cell spar at Red Hawk (GB 877) in 

5,334 ft (1,626 m) of water. Red Hawk is capable of producing 120 MMCFPD, with the flexibility to 

expand to 300 MMCFPD. 

The economics of deepwater development have improved by connecting multiple subsea projects to a 

single hub. For example, Independence Hub will comprise ten separate fields. The rapid growth of 

subsea production systems is illustrated in figure 42. Note the substantial increase in subsea 

developments in the last five years in the 800 to 1,599-m (2,624 to 5,246-ft) water depths. There is a 

corresponding increase in the number of hubs at this same water-depth interval. Figure 43 shows 

production systems for currently producing fields including subsea systems. 

Subsea systems, as shown in figure 44, are capable of producing hydrocarbons from reservoirs covering 

the entire range of water depths that industry is exploring. Subsea systems continue to be a key 

component in the success in deepwater to date. These systems are generally multi-component seafloor 

facilities that allow the production of hydrocarbons in water depths that would normally preclude 

installing conventional fixed or bottom-founded platforms. The subsea system can be divided into two 

major components: the seafloor equipment and the surface equipment. The seafloor equipment will 

include some or all of the following: one or more subsea wells, manifolds, control umbilicals, and 

flowlines. The surface component of the subsea system includes the control system and other production 

equipment located on a host platform that could be located many miles from the actual wells. 
55 

Figure 39. Deepwater development systems. 
56 

Table 7 

Development Systems of Productive Deepwater GOM Projects 

Year of First 

Production Project Name2

 Operator Block Water 

Depth (ft) System Type DWRR3

1979 Cognac Shell MC 194 1,023 Fixed Platform 

1984 Lena ExxonMobil MC 280 1,000 Compliant Tower 

19881 GC 29 Placid GC 29 1,554 Semisubmersible/ 

Subsea 

19881 GC 31 Placid GC 31 2,243 Subsea 

1989 Bullwinkle Shell GC 65 1,353 Fixed Platform 

1989 Jolliet ConocoPhillips GC 184 1,760 TLP 

1991 Amberjack BP MC 109 1,100 Fixed Platform 

1992 Alabaster ExxonMobil MC 485 1,438 Subsea 

19931 Diamond Kerr-McGee MC 445 2,095 Subsea 

1993 Zinc ExxonMobil MC 354 1,478 Subsea 

1994 Auger Shell GB 426 2,860 TLP 

1994 Pompano/ 

Pompano II BP VK 989 1,290 Fixed Platform/ 

Subsea 

1994 Tahoe/SE Tahoe Shell VK 783 1,500 Subsea 

19951 Cooper Newfield GB 388 2,600 Semisubmersible 

1995 Shasta ChevronTexaco GC 136 1,048 Subsea 

1995 VK 862 Walter VK 862 1,043 Subsea 

1996 Mars Shell MC 807 2,933 TLP/Subsea 

1996 Popeye Shell GC 116 2,000 Subsea 

1996 Rocky Shell GC 110 1,785 Subsea 

1997 Mensa Shell MC 731 5,318 Subsea 

1997 Neptune Kerr-McGee VK 826 1,930 Spar/Subsea 

1997 Ram-Powell Shell VK 956 3,216 TLP 

1997 Troika BP GC 200 2,721 Subsea 

1998 Arnold Marathon EW 963 1,800 Subsea 

1998 Baldpate Amerada Hess GB 260 1,648 Compliant Tower 

1998 Morpeth Eni EW 921 1,696 TLP/Subsea 

1998 Oyster Marathon EW 917 1,195 Subsea 

1999 Allegheny Eni GC 254 3,294 TLP 

1999 Angus Shell GC 113 2,045 Subsea 

1999 Dulcimer Mariner GB 367 1,120 Subsea Yes 

1999 EW 1006 Walter EW 1006 1,884 Subsea 

1999 Gemini ChevronTexaco MC 292 3,393 Subsea 
57 

Table 7 

Development Systems of Productive Deepwater GOM Projects 

Year of First 

Production Project Name2

 Operator Block Water 

Depth (ft) System Type DWRR3

1999 Genesis ChevronTexaco GC 205 2,590 Spar 

1999 Macaroni Shell GB 602 3,600 Subsea 

1999 Penn State Amerada Hess GB 216 1,450 Subsea 

1999 Pluto Mariner MC 674 2,828 Subsea Yes 

1999 Ursa Shell MC 809 3,800 TLP 

1999 Virgo TotalFinaElf VK 823 1,130 Fixed Platform Yes 

2000 Black Widow Mariner EW 966 1,850 Subsea Yes 

2000 Conger Amerada Hess GB 215 1,500 Subsea 

2000 Diana ExxonMobil EB 945 4,500 Subsea 

2000 Europa Shell MC 935 3,870 Subsea 

2000 Hoover ExxonMobil AC 25 4,825 Spar 

2000 King Shell MC 764 3,250 Subsea 

2000 Marlin BP VK 915 3,236 TLP 

2000 Northwestern Amerada Hess GB 200 1,736 Subsea Yes 

2000 Petronius ChevronTexaco VK 786 1,753 Compliant Tower 

2001 Brutus Shell GC 158 3,300 TLP 

2001 Crosby Shell MC 899 4,400 Subsea 

2001 Einset Shell VK 872 3,500 Subsea Yes 

2001 EW 878 Walter EW 878 1,585 Subsea Yes 

2001 Ladybug ATP GB 409 1,355 Subsea Yes 

2001 Marshall ExxonMobil EB 949 4,376 Subsea 

2001 MC 68 Walter MC 68 1,360 Subsea 

2001 Mica ExxonMobil MC 211 4,580 Subsea 

2001 Nile BP VK 914 3,535 Subsea 

2001 Oregano Shell GB 559 3,400 Subsea 

2001 Pilsner Unocal EB 205 1,108 Subsea Yes 

2001 Prince El Paso EW 1003 1,500 TLP Yes 

2001 Serrano Shell GB 516 3,153 Subsea 

2001 Typhoon ChevronTexaco GC 237 2,679 TLP Yes 

2002 Aconcagua TotalFinaElf MC 305 7,100 Subsea Yes 

2002 Aspen BP GC 243 3,065 Subsea Yes 

2002 Boomvang North Kerr-McGee EB 643 3,650 Truss Spar Yes 

2002 Camden Hills Marathon MC 348 7,216 Subsea Yes 

2002 Horn Mountain BP MC 127 5,400 Truss Spar Yes 
58 

Table 7 

Development Systems of Productive Deepwater GOM Projects 

Year of First 

Production Project Name2

 Operator Block Water 

Depth (ft) System Type DWRR3

2002 King BP MC 84 5,000 Subsea 

2002 King Kong Mariner GC 472 3,980 Subsea Yes 

2002 King's Peak BP DC 133 6,845 Subsea Yes 

2002 Lost Ark Samedan EB 421 2,960 Subsea Yes 

2002 Madison ExxonMobil AC 24 4,856 Subsea 

2002 Manatee Shell GC 155 1,939 Subsea Yes 

2002 Nansen Kerr-McGee EB 602 3,675 Truss Spar Yes 

2002 Navajo Kerr-McGee EB 690 4,210 Subsea Yes 

2002 Princess Shell MC 765 3,600 Subsea 

2002 Sangria Spinnaker GC 177 1,487 Subsea Yes 

2002 Tulane Amerada Hess GB 158 1,054 Subsea Yes 

2002 Yosemite Mariner GC 516 4,150 Subsea Yes 

2003 Boomvang East Kerr-McGee EB 668 3,795 Subsea Yes 

2003 Boomvang West Kerr-McGee EB 642 3,678 Subsea Yes 

2003 Boris BHP GC 282 2,378 Subsea Yes 

2003 Dawson Kerr-McGee GB 669 3,152 Subsea Yes 

2003 Durango Kerr-McGee GB 667 3,105 Subsea Yes 

2003 East Anstey/ 

Na Kika Shell MC 607 6,590 FPS/Subsea4

 

2003 Falcon Pioneer EB 579 3,638 Subsea Yes 

2003 Fourier/Na Kika Shell MC 522 6,950 FPS/Subsea4 

2003 Gunnison Kerr-McGee GB 668 3,100 Truss Spar Yes 

2003 Habanero Shell GB 341 2,015 Subsea 

2003 Herschel/Na Kika Shell MC 520 6,739 FPS/Subsea4 

2003 Matterhorn TotalFinaElf MC 243 2,850 TLP Yes 

2003 Medusa Murphy MC 582 2,223 Spar Yes 

2003 Medusa North Murphy MC 538 2,223 Subsea Yes 

2003 Pardner Anadarko MC 401 1,139 Subsea Yes 

2003 Tomahawk Pioneer GB 623 3,412 Subsea Yes 

2003 Zia Devon MC 496 1,804 Subsea 

2004 Ariel/Na Kika BP MC 429 6,274 Subsea4 

2004 Coulomb/Na Kika Shell MC 657 7,591 Subsea4 Yes 

2004 Devil’s Tower Dominion MC 773 5,610 Truss Spar Yes 

2004 Diana South ExxonMobil AC 65 4,852 Subsea 
59 

Table 7 

Development Systems of Productive Deepwater GOM Projects 

Year of First 

Production Project Name2

 Operator Block Water 

Depth (ft) System Type DWRR3

2004 Front Runner Murphy GC 338 3,330 Truss Spar Yes 

2004 Glider Shell GC 248 3,440 Subsea 

2004 Hack Wilson Kerr-McGee EB 598 3,650 Subsea Yes 

2004 Harrier Pioneer EB 759 4,114 Subsea Yes 

2004 Holstein BP GC 645 4,344 Truss Spar 

2004 Kepler/Na Kika BP MC 383 5,759 Subsea4 

2004 Llano Shell GB 386 2,663 Subsea Yes 

2004 Magnolia Conoco-Phillips GB 783 4,674 TLP 

2004 Marco Polo Anadarko GC 608 4,320 TLP Yes 

2004 Raptor Pioneer EB 668 3,710 Subsea Yes 

2004 Red Hawk Kerr-McGee GB 877 5,334 Cell Spar Yes 

2005 Citrine LLOG GC 157 2,614 Subsea Yes 

2005 GC 137 LLOG GC 137 1,168 Subsea Yes 

2005 K2 Eni GC 562 4,006 Subsea 

2005 Mad Dog BP GC 782 4,428 Truss Spar 

2005 Swordfish Noble VK 962 4,677 Subsea 

2005 Triton/Goldfinger Dominion MC 728 5,610 Subsea Yes 

2006 Constitution Kerr-McGee GC 680 5,071 Truss Spar 

2006 Gomez ATP MC 711 3,098 Semisubmersible/ 

Subsea 

2006 K2 North Anadarko GC 518 4,049 Subsea 

2006 Rigel Dominion MC 296 5,229 Subsea 

2006 Seventeen Hands Dominion MC 299 5,881 Subsea 

2006 Ticonderoga Kerr-McGee GC 768 5,272 Subsea Yes 

1

 Indicates projects which are no longer on production. 

2

 Editions of this report prior to 2004 listed deepwater fields rather than projects. 3

 Indicates projects with one or more leases approved to receive DWRR. 

4

 Na Kika FPS is located in Mississippi Canyon Block 474 in 6,340 ft (1,932 m) of water. 

AC = Alaminos Canyon 

DC = DeSoto Canyon 

EB = East Breaks 

EW = Ewing Bank 

GB = Garden Banks 

GC = Green Canyon 

MC = Mississippi Canyon 

VK = Viosca Knoll 
60 

Figure 40. Three development systems: a TLP installed at 

Magnolia field, a semisubmersible at Thunder Horse 

field, and a truss spar installed at Holstein field 

(images courtesy of ConocoPhillips and BP/Marc 

Morrison). 
61

Figure 41. Progression of spar deepwater development systems (image courtesy of Technip). 
62 

pre-1996

1996-2000

2001-2005

hubs 200 - 399 m

hubs 400 - 799 m

hubs 800 - 1,599 m

hubs > 1,600 m

subseas 200 - 399 m

subseas 400 - 799 m

subseas 800 - 1,599 m

subseas > 1,600 m

1

11 7

29

5 9 9

2

2 4

3

1 6

11

4

3

2

4

1

0

5

10

15

20

25

30

Number of Productive Projects

Years

hubs 200 - 399 m

hubs 400 - 799 m 

hubs 800 - 1,599 m 

hubs > 1,600 m

subseas 200 - 399 m

subseas 400 - 799 m

subseas 800 - 1,599 m

subseas > 1,600 m 

Figure 42. The number of subsea projects and hubs for 5-year periods by waterdepth category. 

SEMI-FPS, 3

Compliant Tower, 3

SPAR, 13

FIXED Platform, 6

TLP, 14

Subsea, 184

Figure 43. Production systems for currently producing 

fields, including subsea systems. 
63 

SUBSEA TRENDS

Figure 45 shows the number of subsea completions each year since 1955 (only productive wells were 

counted). There were fewer than ten subsea completions per year until 1993. This number increased 

dramatically throughout the 1990’s. The pie chart in figure 45 shows that shallow-water subsea wells are 

a significant contribution to the subsea well population in the GOM. Shallow-water subsea wells 

accounted for 151 of the 348 total subsea wells in the GOM by yearend 2005. Operators have found 

subsea tiebacks to be valuable for shallow-water marginal fields because of the extensive infrastructure of 

platforms and pipelines. Non-major companies have installed nearly all of these shallow-water subsea 

wells, led by Walter Oil and Gas Corporation with 26 wells. Figure 45 demonstrates the increasing 

reliance of industry on subsea technology to develop shallow-water and deepwater fields, beginning in the 

late 1980’s. 

The technology required to implement subsea production systems in deepwater evolved significantly in 

the last seventeen years. This evolution is apparent in figure 46, which shows that the deepest subsea 

completion was in 350 ft (107 m) of water until 1988, when the water depth record (GOM) jumped to 

2,243 ft or 684 m (Green Canyon 31 project). In 1996, another record was reached with a subsea 

completion in 2,956 ft (901 m) of water (Mars project), followed by a 1997 subsea completion in 5,295 ft 

(1,614 m) of water (Mensa project). Coulomb has the deepest production in the GOM to date, in a water 

depth of 7,591 ft (2,313 m). A listing of productive subsea and temporarily abandoned completions on 

the GOM Outer Continental Shelf can be found in Appendix E. 

Figure 47 further breaks down the subsea completion count into specific water-depth ranges. This figure 

shows that nearly 70 percent of the subsea completions are in water depths less than 2,500 ft (762 m). 

For subsea wells to continue to advance to greater water depths and harsher environments, improvements 

in technology are necessary. Currently MMS is working with industry to ensure that new advancements 

are developed in a safe and environmentally conscientious manner. Some concepts currently under 

evaluation include high integrity pressure protection systems (HIPPS), high-pressure, high-temperature 

(HPHT) materials, and subsea processing. 

INDEPENDENCE HUB

Independence Hub, LLC, an affiliate of Enterprise Products Partners L.P., has entered into agreements 

with the Atwater Valley Producers Group to gather natural gas from ten fields in the deepwater GOM. 

Atwater Valley Producers Group includes Anadarko Petroleum Corporation, Dominion Exploration & 

Production, Inc., Kerr-McGee Oil & Gas Corporation, Hydro Gulf of Mexico, LLC (formerly Spinnaker), 

Devon Energy Corporation, and Energy Resources Technology, Inc. (subsidiary of Cal Dive 

International, Inc.). Enterprise Products Partners will design, construct, install, and own the 

Independence Hub; Anadarko will operate it. 

Independence Hub will be located on unleased Mississippi Canyon Block 920 in a water depth of 

approximately 8,000 ft (2,438 m). The selection of the location for the permanently moored host facility 

was based on seafloor conditions and proximity to the anchor fields: Atlas (LL 50), Atlas NW (LL 5), 

Cheyenne (LL 399), Jubilee (AT 349), Merganser (AT 37), Mondo Northwest (LL 2), San Jacinto (DC 

618), Q (MC 961), Spiderman (DC 621), and Vortex (AT 261) (see table 8). The 105-ft (32-m) deepdraft, semisubmersible platform will have capacity to produce 1.0 BCFPD. The platform is designed to 

process production from the initial 10 anchor fields, with excess payload capacity to tie-back up to nine 

additional subsea pipelines. Installation is slated for late 2006 and first production is expected in mid2007. 
64

Subsea Wellhea

Subsea Manifold

Flow line jumper

Electrical & Hydraulic Control Umbilical

Well # 1

Well # 2

Well # 3

Subsea Umbilical Termination Assembly (SUTA)

Flow lines to host platform

Figure 44. Crosby Project (MC 899) subsea equipment layout (image courtesy of Shell International Exp

and Production Inc.). 
65 

Table 8 

Independence Hub Anchor Fields 

Discovery Area/Block Water Depth 

(ft) 

Sale 

No. Sale Year 1st Well Spud Years to Spud* 

Mondo NW LL 2 8,340 116 1988 2004 14.53 

Vortex AT 261 8,422 157 1996 2002 6.28 

Jubilee AT349 8,891 166 1997 2003 5.58 

Merganser AT 37 8,064 175 2000 2001 1.35 

Atlas LL 50 9,180 181 2001 2003 1.19 

Atlas NW LL 5 8,810 181 2001 2003 1.81 

San Jacinto DC 618 7,850 181 2001 2004 2.17 

Spiderman DC 621 8,100 181 2001 2003 1.66 

Cheyenne LL 399 8,987 181 2001 2004 2.30 

Q MC 961 7,925 190 2004 2005 1.04 

* based on lease effective date 

NEW PIPELINES

The pipeline infrastructure to bring deepwater oil and gas onshore also expanded during the 1990’s. The 

pipeline from a subsea completion to the host platform is commonly referred to as the tieback. The 

tieback length varies considerably, as shown in figure 48. Most subsea wells are within 10 mi (16 km) of 

the host platform, with the Mensa field remaining the current world record holder for a subsea tieback 

length of 62 mi (100 km) from the host platform. The second longest subsea tieback in the world (55 mi 

or 88 km) is Canyon Express, linking Aconcagua, Camden Hills, and King’s Peak projects to their host 

platform. 

Deepwater pipelines approved for installation are shown in figures 49a and 49b. The data include the 

total length of all pipelines originating at a deepwater development, including any shallow-water 

segments (control umbilicals are excluded). Figure 49a shows deepwater pipelines that are less than or 

equal to 12 inches (30.5 cm) in diameter. The dominance of gas pipeline miles approved in deepwater is 

surprising — 62 percent of the total since 1990. The large increase in 2001 in oil and gas pipeline miles 

reflects approvals for Canyon Express (Aconcagua, Camden Hills, and King’s Peak fields), Horn 

Mountain, and the Boomvang-Nansen projects. Last year saw the approval of the largest number of miles 

of pipelines less than or equal to 12 inches in diameter since the peak year of 2001. Pipelines for the 

facilities at Gomez, Triton, and Independence Hub account for the significant increase. 
66 

0

5

10

15

20

25

30

35

40

1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005

Year

Number of Subsea Completions

Shallow water

Deepwater

Deepwater

57%

Shallow water

43%

Figure 45. Number of shallow- and deepwater subsea completions each year. 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005

Year

Maximum Water Depth (ft)

HI A573

GC 31

Mars

Mensa

King's Peak

Camden Hills

Figure 46. Maximum water depth of subsea completions installed each year. 
67 

151

91

77

25

6

0

20

40

60

80

100

120

140

160

Number of Wells

< 1,000 ft 1,000-2,499 ft 2,500-4,999 ft 5,000-6,999 ft >7,000 ft

Water Depth Range

Figure 47. Water depth of subsea completions. 

199

81 84

20

11

5

0

20

40

60

80

100

120

140

160

180

200

Number of Pipeline Segments

< 5 5 - 9 10 - 19 20 - 29 30 - 49 50+

Tieback Length Range (mi)

Figure 48. Length of subsea tiebacks. 
68 

9

32 42

173

49

101

121

86

108

62

28

89

201

278

167

179

53

76

53

80

103

284

0

100

200

300

400

500

600

700

Miles of Pipelines Approved

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

Gas

Oil

Figure 49a. Approved deepwater oil and gas pipelines less than or equal to 12 inches in 

diameter. 

40

41

40 39

46 103

65

179

129

25

32

41

76

293

326

156

225

43

11 67

30

0

100

200

300

400

500

600

700

Miles of Pipeline Approved

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

Year

Gas

Oil

Figure 49b. Approved deepwater oil and gas pipelines greater than 12 inches in diameter. 
69 

Installation of large pipelines (greater than 12 inches [30.5 cm] in diameter) dramatically increased in 

2002 after a brief downturn in activity in 2000 and 2001 (figure 49b). The peak in 2002 was driven by 

the approval of the Mardi Gras system. Gas and oil from the Mardi Gras system is delivered to onshore 

processing facilities via the new Cameron Highway pipeline system, which has been a very important 

development in pipeline infrastructure. In addition, Kerr-McGee’s Constitution and Red Hawk facilities 

have installed export pipelines, both oil and gas, which have added significantly to the overall pipeline 

system. The newest approved transportation lines are from the Independence Hub facility. These lines 

will be installed in the near future. 

The infrastructure needed to bring deepwater production online continues to develop over time. Figure 50 

shows the framework of major oil and gas pipelines in the GOM. Figure 51 illustrates the existing 

network of deepwater pipelines. These figures highlight new and proposed pipelines since the 2004 

report. 

HIGH INTEGRITY PRESSURE PROTECTION SYSTEM (HIPPS) 

The longer subsea tiebacks being used to develop marginal deepwater fields pose another challenge for 

industry, namely in the design and installation of pipelines rated for the HPHT well’s shut-in tubing 

pressure (SITP) of 15,000 pounds per square inch (psi) and/or 350o

 F (177o C). Rather than relying on the 

physical strength of steel to withstand the SITP, a high integrity pressure protection system (HIPPS) 

provides alternate over-pressure protection for a pipeline or flowline. HIPPS employs valves, logic 

controllers, and pressure transmitters to shut down the system before a pipeline is overpressured and/or 

ruptured. 

The MMS has been working with the American Petroleum Institute (API) and DeepStar to formulate the 

regulatory framework for the installation of an HIPPS in the GOM. DeepStar is a joint industry 

technology development project representing large and mid-size operators to help address common 

deepwater business challenges. 

DeepStar is expected to finish its HIPPS study in 2006, and API will address HIPPS in its Recommended 

Practice API RP 17 O in late 2006 or early 2007. However, it is anticipated that the GOM Region will 

receive applications for the use of an HIPPS in 2006. Once design specifications for each section of the 

HIPPS system are finalized, MMS will hold operators to the design codes. 
70

		











 

  

  

	
 		
 			


Figure 50. Oil and gas pipelines with diameters greater than or equal to 20 inches. 
71 

		  













		 



















	

	


  	

   

   

Figure 51. Deepwater oil and gas pipelines in the Gulf of Mexico. 
73 

RESERVES AND PRODUCTION 

The deepwater GOM has contributed major additions to the total reserves in the GOM. Figure 52 shows 

the proved reserves added each year by water-depth category. Additions from the shallow waters of the 

GOM declined in recent years but, beginning in 1975, the deepwater area started contributing significant 

new reserves. Between 1975 and 1983, the majority of these additions were from discoveries in slightly 

more than 1,000 ft (305 m) of water. It was not until 1985 that major additions came from water depths 

greater than 1,500 ft (457 m). 

There is often a significant lag between a successful exploratory well and its hydrocarbons being 

produced. The success of an exploratory well may remain concealed from the public for several years 

until the operator requests a “Determination of Well Producibility” from MMS. A successful MMS 

determination then “qualifies” the lease as producible and the discovery is placed in a field. The 

discovery date of that field is then defined as the TD (total depth) date of the field’s first well that 

encountered significant hydrocarbons. Hydrocarbon reserves are still considered unproved until it is clear 

that the field will go on production. Then the reserves move into MMS’s proved category. Figure 53 

includes both proved and unproved reserves for each water-depth category. This figure shows declining 

reserve additions in shallow water, similar to figure 52, but reveals significantly more deepwater reserve 

additions and large significant unproved reserve additions in water depths greater than 5,000 ft (1,524 m) 

beginning in 1998. 

Figure 54 illustrates the most important feature of the deepwater field discoveries, that their average size 

is many times larger than the average size of shallow-water fields. During the last 10 years, the average 

shallow-water field added approximately 5 MMBOE of proved and unproved reserves. In contrast, the 

average deepwater field added over 67 MMBOE of proved and unproved reserves. 

DISCOVERIES

Figure 55 shows the number of deepwater fields discovered each year, according to MMS criteria, since 

1975. (See appendix A for a listing of deepwater projects and discoveries.) The number of field 

discoveries for any given year is usually greater than the number of fields that actually go on production. 

The difference between the number of field discoveries and the number of those that actually produce 

increased in the early 2000’s, since these recent field discoveries have had little time to reach production. 

Because of this lag between exploratory drilling and first production, the true impact of recent, large 

deepwater exploratory successes is not yet reflected in MMS proved and unproved reserve estimates. 

In an attempt to capture the impact of these deepwater exploratory successes, figure 56 adds MMS-known 

resource estimates and industry-announced discoveries to the proved and unproved reserve volumes. The 

industry-announced discovery volumes contain considerable uncertainty, are based on limited drilling, 

include numerous assumptions, and have not been confirmed by independent MMS analyses. They do, 

however, illustrate recent activity better than using only MMS proved reserve numbers. The apparent 

decline of proved reserve additions in recent years is caused by the previously mentioned developmental 

lag. 

Figure 57 illustrates the distribution of recent hydrocarbon additions in the GOM, categorized by water 

depth. The combination of industry-announced deepwater discoveries and MMS estimates illustrates that 

deepwater exploration is adding significantly to the GOM hydrocarbon inventory. These large additions 

show the excellent potential for continued growth in deepwater activity levels. 
74 

0

500

1,000

1,500

2,000

2,500

3,000

196519671969197119731975197719791981198319851987198919911993199519971999200120032005

Year

Million Barrels of Oil Equivalent 

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

0 - 999 ft

Figure 52. Proved reserve additions. 

0

500

1,000

1,500

2,000

2,500

3,000

196519671969197119731975197719791981198319851987198919911993199519971999200120032005

Year

Million Barrels of Oil Equivalent

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

0 - 999 ft

Figure 53. Proved and unproved reserve additions. 
75 

0

100

200

300

400

500

600

196519671969197119731975197719791981198319851987198919911993199519971999200120032005

Year

Million Barrels of Oil Equivalent

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

0 - 999 ft

Figure 54. Average field size using proved and unproved reserves. 

0

2

4

6

8

10

12

14

16

18

20

22

24

1975197719791981198319851987198919911993199519971999200120032005

Field Discovery Year

Number of Fields

Number of discoveries (MMS qualified)

Number producing

Figure 55. Number of deepwater field discoveries and resulting number of producing fields. 
76 

0

500

1000

1500

2000

2500

3000

1975197619771978197919801981198219831984198519861987198819891990199119921993199419951996199719981999200020012002200320042005

Field Discovery Year

Million Barrels of Oil Equivalent

0

5

10

15

20

25

Number of Discoveries

Proved reserves

Unproved reserves, resources, and industry-announced discoveries

Number of discoveries (MMS qualified)

Figure 56. Number of deepwater field discoveries and new hydrocarbons found (MMS 

reserves, MMS resources, and industry-announced discoveries). 

0

500

1,000

1,500

2,000

2,500

3,000

196519671969197119731975197719791981198319851987198919911993199519971999200120032005

Year

Million Barrels of Oil Equivalent

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

0 - 999 ft

Figure 57. BOE added (reserves, known resources, and industry-announced discoveries). 
77 

PRODUCTION TRENDS

Seismic acquisition, leasing, bid rejects, drilling, and discoveries—all stepped into deeper waters with 

time. The final piece in the puzzle, production, is no exception. Figure 58 illustrates the relative volume 

of production from each GOM block through time. Notice the large deepwater volumes that first appear 

in 1996 and 1997. More recent production continues to expand over a larger area and into deeper waters. 

Table 9 shows that the most prolific blocks (on a BOE basis) are currently in the deepwater GOM. 

Table 9 

Top 20 Producing Blocks for the Years 2003–2004 

Block Project Name Owner Water Depth (ft) Production (BOE)* 

MC 807 Mars Shell 2,933 93,697,105 

MC 809 Ursa Shell 3,800 55,745,876 

MC 127 Horn Mountain BP 5909 41,587,128 

MC 763 Mars Shell 3,261 34,808,598 

GB 215 Conger Amerada Hess 1,500 32,908,596 

VK 786 Petronius ChevronTexaco 1,753 28,140,012 

MC 765 Princess Shell 3,600 26,557,440 

EB 602 Nansen Kerr-McGee 3,675 25,711,854 

MC 686 Mensa Shell 5,364 24,876,468 

EB 643 Boomvang Kerr-McGee 3,650 24,650,727 

MC 305 Aconcagua Total 7,100 22,071,492 

GC 202 Brutus Shell 3,327 21,938,285 

EB 945 Diana ExxonMobil 4,500 21,857,743 

MC 85 King BP 5,689 18,400,654 

MC 899 Crosby Shell 4,259 18,135,470 

GC 243 Aspen Nexen 3,065 18,111,481 

VK 915 Marlin BP 3,236 17,746,359 

VK 912 Ram Powell Shell 3,216 17,278,987 

ST 37 Unnamed ChevronTexaco 59 15,834,599 

MP 61 Unnamed POGO 151 15,201,087 

*cumulative production from January 2003 through December 2004 

Figure 59 illustrates the importance of the GOM to the Nation’s energy supply. The GOM supplies 

approximately 28 percent of the Nation’s domestic oil and 20 percent of the Nation’s domestic gas 

production. A significant portion of these volumes comes from the deepwater. 
78 





	







 

 	
 	



 









 




 


 








 

 	
 	



 









 










 

 	
 	



 









 




Figure 58. Relative volume of production from each GOM lease. Bar heights are 

proportional to total lease production (barrels of oil equivalent) during that 

interval. 
79 







 

 	
 	



 









 










 

 	
 	



 









 




 

	
 








 

 	
 	



 









 










Figure 58. Relative volume of production from each GOM lease. Bar heights are 

proportional to total lease production (barrels of oil equivalent) during that 

interval (continued). 
80








Figure 58. Relative volume of production from each GOM lease. Bar heights are proportional to total lease producti

equivalent) during that interval (continued). 
81 

Gas

Shallow-water 

GOM

10%

Deepwater 

GOM

18%

Other U.S.

72%

Oil

Other U.S.

80%

Shallow-water 

GOM

13%

Deepwater 

GOM

7%

Gas

Figure 59. Estimated U.S. oil and gas production in 2004. 

Figure 60a illustrates historic trends in oil production. Shallow-water oil production rose rapidly in the 

1960’s, peaked in 1971, and has undergone cycles of increase and decline since then. Since 1997, the 

shallow-water GOM oil production has steadily declined and, at the end of 2004, was at its lowest level 

since 1967. From 1995 through 2003, deepwater oil production experienced a dramatic increase similar 

to that seen in the shallow-water GOM during the 1960’s, offsetting recent declines in shallow-water oil 

production. Starting in 2003, deepwater oil production levelled off. In 2004, deepwater oil production 

accounted for approximately 64 percent of GOM oil production. 

Figure 60b shows similar production trends for gas. Shallow-water gas production rose sharply 

throughout the 1960’s and 1970’s, and then remained relatively stable over the next 15 years before 

declining steadily from 1996 through today. Although the deepwater gas production increase has not 

been as dramatic as with oil, the increase in deepwater gas production that occurred in the past few years 

helped to offset the shallow-water decline. Similar to deepwater oil production, gas production levelled 

off beginning in 2003. Appendix F lists historic GOM oil and gas production. These trends in oil and gas 

production indicate that the deepwater GOM frontier continues to expand. 

As discussed previously, the Deepwater Royalty Relief Act (DWRRA) had a significant effect on 

deepwater leasing and drilling. Numerous projects with royalty relief eligibility have come online in 

recent years (table 7), but the impact of the DWRRA on deepwater production began to show in 2002. 

Figure 61a shows the contribution of Deepwater Royalty Relief (DWRR) oil production to total 

“deepwater” GOM oil production, where “deepwater” is defined as 200 m (656 ft), the minimum water 

depth for which DWRR incentives are offered, instead of 1,000 ft (305 m), the definition used elsewhere 

in this report. Since the 2004 report (Richardson et al.), the amount of oil production subject to royalty 

suspension increased significantly to 21 percent of the total “deepwater” production. Figure 61b displays 

total “deepwater” gas production along with gas production subject to royalty relief. The volume of 

natural gas subject to royalty relief under the DWRRA increased rapidly in 2002, reaching 29 percent of 

total “deepwater” production by March 2004. Note that pre-DWRRA production refers to production 

from leases that have been approved to receive royalty relief but were issued before November 28, 1995. 

Approximately 350,000 barrels of oil and 1.7 billion cubic feet of gas come from deepwater subsea 

completions each day. Subsea completions currently account for about 34 percent of deepwater oil 
82 

0

200

400

600

800

1,000

1,200

19471950195319561959196219651968197119741977198019831986198919921995199820012004

Year

Thousand Barrels of Oil per Day

Shallow-water oil

Deepwater oil

Figure 60a. Comparison of average annual shallow- and deepwater oil production. 

0

2

4

6

8

10

12

14

16

19471950195319561959196219651968197119741977198019831986198919921995199820012004

Year

Billion Cubic Feet of Gas per Day

Shallow-water gas

Deepwater gas

Figure 60b. Comparison of average annual shallow- and deepwater gas production. 
83 

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04

Month

Barrels of Oil per Day

Total oil production >200 m (656 ft)

Contribution of pre-DWRRA production

Contribution of DWRRA production

Figure 61a. Contribution of DWRRA oil production to total oil production in water depths greater 

than 200 m (656 ft). 

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

5,000,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04

Month

Thousand Cubic Feet per Day

Total gas production >200 m (656 ft)

Contribution of pre-DWRRA production

Contribution of DWRRA production

Figure 61b. Contribution of DWRRA gas production to total gas production in water depths greater 

than 200 m (656 ft). 
84 

production and about 50 percent of deepwater gas production. Figure 62a shows that very little 

deepwater oil production came from subsea completions until mid-1995, but by the fall of 1996 that 

production had risen to about 20 percent. Since 2000, subsea oil production has increased slightly, 

whereas total deepwater oil production has increased dramatically. Deepwater gas production from 

subsea completions began in early 1993, and by mid-1994 it accounted for over 40 percent of deepwater 

GOM gas production (Figure 62b). Gas production from subsea completions increased from 1996 

through 1999, remained constant in 2000, and increased rapidly after 2000. 

PRODUCTION RATES

High well production rates have been a driving force behind the success of deepwater operations. Figure 

63a illustrates the highest deepwater oil production rates (monthly production divided by actual 

production days). For example, a well within Shell’s Bullwinkle field produced about 5,000 BOPD in 

1992. In 1994, a well within Shell’s Auger field set a record, producing about 10,000 BOPD. From 1994 

through mid-1999, maximum deepwater oil production rates continued to climb, especially in water 

depths between 1,500 and 4,999 ft (457 and 1,524 m). Horn Mountain came online in early 2002 in 

5,400-ft (1,646-m) water depth with a single well maximum rate of more than 30,000 BOPD. Since mid2002, oil production rates have declined in the 1,500 to 4,999-ft (457 to 1,524-m) water-depth interval; 

however, production rates have increased steeply in the greater than and equal to 5,000-ft (1,524-m) 

water-depth interval. The record daily oil production rate (for a single well) is 41,532 BOPD (Troika). 

Figure 63b shows maximum production rates for gas. These rates hovered around 25 MMCFPD until a 

well in Shell’s Popeye field raised the deepwater production record to over 100 MMCFPD in 1996. Since 

then, the deepwater has yielded even higher maximum production rates. In 1997, Shell’s Mensa field 

(5,379-ft [1,640-m] water depth) showed the excellent potential for deepwater production rates beyond 

the 5,000-ft (1,524-m) water-depth interval. The record daily gas production rate is 158 MMCFPD 

(Mensa). 

Figure 64a shows that the average deepwater oil completion currently produces at about 25 times the rate 

of the average shallow water (less than 1,000 ft [305 m]) oil completion. The average deepwater gas 

completion currently produces at about 8 times the rate of the average shallow-water gas completion 

(figure 64b). Deepwater oil production rates increased rapidly from 1996 through 2000 and remained 

steady since that time. Deepwater gas production rates rose from 1996 to mid-1997 and then stabilized at 

the current high rates. 

Two trends are readily apparent in figures 65a-b. First, average oil production rates per well for 

deepwater are more than 10 times greater than the rates for shallow water, especially in the later years. In 

addition, rates are declining from their peak production more rapidly in deepwater after 1998. These 

figures show monthly average oil production rates for all wells that began production in a specific year. 

For example, in figure 65a, the 1992 line represents oil well production for deepwater oil wells completed 

in 1992 divided by the number of oil wells which began production in that year. The 1992 line tracks 

production from these completions in successive years. 

Figures 66a (oil) and 66b (gas) compare maximum historic production rates for each lease in the GOM, 

i.e., the well with the highest historic production rate is shown for each lease. These maps show that 

many deepwater fields produce at some of the highest rates encountered in the GOM. Figure 66a also 

shows that maximum oil rates were significantly higher off the southeast Louisiana coast than off the 

Texas coast. Figure 66b illustrates the high deepwater gas production rates relative to the rest of the 

GOM. Note also the excellent production rates from the Norphlet trend (off the Alabama coast) and the 

Corsair trend (off the Texas coast). 
85 

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

1,000,000

1,100,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04

Month

Barrels of Oil per Day

Subsea oil

Total deepwater oil

Figure 62a. Contributions from subsea completions toward total deepwater oil production. 

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

5,000,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04

Month

Thousand Cubic Feet of Gas per Day

Subsea gas

Total deepwater gas

Figure 62b. Contributions from subsea completions toward total deepwater gas production. 
86 

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04

Month

Barrels of Oil per Day

Max oil rate 1,000-1,499 ft

Max oil rate 1,500-4,999 ft

Max oil rate >5,000 ft

Bullwinkle

Auger

Mars

Troika

Ursa

Horn Mountain

Brutus

Kepler (Na Kika)

Figure 63a. Maximum production rates for a single well within each water-depth category for 

deepwater oil production. 

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04

Month

Thousand Cubic Feet of Gas per Day

Max gas rate 1,000-1,499 ft

Max gas rate 1,500-4,999 ft

Max gas rate >5,000 ft

Bullwinkle

Diamond

Popeye

Mensa

Mensa

Mica

Figure 63b. Maximum production rates for a single well within each water-depth category for 

deepwater gas production. 
87 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04

Month

Barrels of Oil per Day

Shallow water

Deepwater

Figure 64a. Average production rates for shallow-water and deepwater oil well completions. 

0

5,000

10,000

15,000

20,000

25,000

30,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04

Month

Thousand Cubic Feet of Gas per Day

Shallow water

Deepwater

Figure 64b. Average production rates for shallow-water and deepwater gas well completions. 
88 

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04

Month

Average Daily Oil Production BOPD

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

844

1965

3543

4045

3964

12432

9368

7106

6527

6077

6375

Figure 65a. Deepwater oil production profiles (oil wells coming onstream between 1992 and 

2004). 

0

200

400

600

800

1000

1200

1400

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04

Month

Average Daily Oil Production BOPD

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

358 399 392

559

452

484

461

487

342 360

487

428

342

Figure 65b. Shallow-water oil production profiles (oil wells coming onstream between 1992 and 

2004).
89



		 





 







	




	

	

 	

  

   

 	 

!	

"#	

	

Figure 66a. Maximum historic oil production rates for Gulf of Mexico wells. 
90

Figure 66b. Maximum historic gas production rates for Gulf of Mexico wells. 
91 

SHALLOW-WATER FIELD VERSUS DEEPWATER FIELD PERFORMANCE

A comparison of the performance of shallow-water fields and deepwater fields is admittedly tenuous 

because today’s advances in technology were not available during the heyday of shallow-water 

development. However, empirical comparisons may be revealing. Figures 67a and 67b compare 

cumulative production and total recoverable reserves for four deepwater fields and four shallow-water 

fields. Each of the fields is still on production. The deepwater fields represent the top four in the 

deepwater GOM in terms of cumulative production through 2004: Mars-Ursa (MC 807), Auger (GB 426), 

Troika (GC 244), and Pompano (VK 990). These fields are compared to shallow-water fields with similar 

cumulative production and/or recoverable reserves. 

Cumulative oil production and total recoverable oil are shown in figure 67a. The number of years for 

which the fields have been on production is annotated at the top of the histograms. The figure shows that 

deepwater fields have produced similar amounts of oil significantly faster than shallow-water fields. 

Cumulative gas production and recoverable gas are shown in figure 67b. To date, Eugene Island 330 (EI 

330) field has produced more than twice the amount of gas as Mars-Ursa (MC 807). Of that total 

production, EI 330 field produced approximately 800 BCF in 9 years, comparable to the amount produced 

in 8.5 years at Mars-Ursa. However, the other shallow-water fields took much longer to reach cumulative 

levels of gas production than deepwater fields of similar size. 

HURRICANE ACTIVITY

Ivan 

On Monday, September 13, 2004, Hurricane Ivan entered the GOM after crossing the western tip of 

Cuba. It was projected to make landfall on the northern Gulf coast early Thursday, September 16, 2004, 

with sustained winds up to 130 miles per hour (mph). In anticipation of its arrival, 69 rigs (~60% of the 

rigs currently drilling in the GOM) and 575 manned platforms (~75% of the Gulf’s manned platforms) 

were evacuated. All evacuations were completed without injury to personnel. By Thursday afternoon, 

over 70 percent of the GOM’s daily oil production and about 60 percent of its daily gas production were 

shut in. Approximately 150 platforms and 10,000 mi of pipeline were in the projected path of Ivan. The 

hurricane accounted for the destruction of 7 platforms (all in shallow water) by mudslides, significant 

damage to another 24 major platforms (shallow and deepwater), and damage to at least 102 pipelines. 

The eye of Hurricane Ivan passed almost directly over the Petronius facility (VK 786), resulting in 

significant damage to the crew quarters, production equipment, and deck structures. The facility was 

back online by mid-March 2005. Appendix G lists all platforms destroyed by Hurricanes Ivan, Katrina, 

and Rita. 

Katrina and Rita 

On Friday, August 26, 2005, Hurricane Katrina entered the GOM after crossing southeastern Florida. By 

August 28th, Katrina had grown from a category 3 to a category 5 hurricane. It made landfall on the 

northern Gulf coast Monday, August 29, 2005, as a category 3 hurricane with sustained winds up to 120 

miles per hour (mph). Hurricane Rita followed quickly on the heels of Katrina, entering the GOM on 

September 20, 2005. Rita grew to a category 5 hurricane over the warm waters of the GOM, finally 

making landfall on the Texas/Louisiana border on September 24, 2005 as a category 3 storm. Over 90 

percent of the manned platforms and over 85 percent of working rigs were evacuated at the onset of these 

two monstrous storms. One hundred percent of the oil production (1.5 MMBOPD), along with 94 percent 

of the gas production (10 BCFPD), was shut in during Hurricanes Katrina and Rita. Figure 68 shows the 

paths of Katrina and Rita in the GOM and the platforms within the storm tracks. Approximately 3,050 

platforms and 22,000 mi of pipeline were in the projected paths of these storms. These two hurricanes 

accounted for the destruction of more than 100 platforms (all in shallow water except Typhoon in GC 

237). 
92 

Of the total shut-in GOM production caused by Hurricanes Katrina and Rita, deepwater represented the 

greater percent (figures 69a-b). As of March 22, 2006, 23 percent of the daily oil production and 14 

percent of the daily gas production was shut in. 

Restoring production in the deepwater Gulf of Mexico has unique challenges. As of first quarter 2006, 

repairs of the damage to the oil and gas pipelines caused by Hurricane Katrina were underway at Shell’s 

Mars facility (MC 807). This constitutes a world record in water depth for pipeline repair (approximately 

3,000 ft [914 m] of water). 

0

200

400

600

800

1,000

1,200

MC807 EI330 GB426 SP089 GC244 SP062 VK990 SS230

Field

Million Barrels of Oil

Cumulative MMBO produced

MMBO recoverable

Mars-Ursa

3,800' wd

Auger

2,860' wd Troika 

2,721' wd

Pompano 

1,290' wd

8.5 yrs

10.8 yrs

32.4 yrs

26.4 yrs 7.2 yrs 37.2 yrs

10.3 yrs 36.4 yrs

Figure 67a. Cumulative oil production and ultimate recoverable reserves for 

selected shallow-water and deepwater fields. 

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

MC807 EI330 GB426 SP089 GC244 SP062 VK990 SS230

Field

Billion Cubic Feet

Cumulative BCF produced

BCF recoverable

Mars-Ursa

3,800' wd

8.5 yrs

32.4 yrs

10.8 yrs

Auger

2,860' wd

26.4 yrs

Troika 

2,721' wd

7.2 yrs

37.2 yrs

Pompano 

1,290' wd

10.3 yrs

36.4 yrs

9 yrs

Figure 67b. Cumulative gas production and ultimate recoverable reserves for 

selected shallow-water and deepwater fields. 
93

Figure 68. Platforms within the path of Hurricanes Katrina and Rita in the Gulf of Mexico. 
94 

0

200

400

600

800

1,000

1,200

1,400

1,600

31-Aug-05

11-Sep-0518-Sep-0524-Sep-0525-Sep-0526-Sep-0527-Sep-0528-Sep-05

11-Oct-0531-Oct-05

13-Nov-05

1-Dec-05

15-Dec-0531-Dec-05

Date

Thousand Barrels of Oil Per Day

0

10

20

30

40

50

60

70

80

90

GOM oil shut in

Deepwater Percent of Total Oil Shut In

Deepwater oil shut in

Deepwater percent of total GOM oil shut in

Figure 69a. Comparison of total GOM oil shut in and GOM deepwater oil shut in. 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

31-Aug-05

11-Sep-0518-Sep-0524-Sep-0525-Sep-0526-Sep-0527-Sep-0528-Sep-05

11-Oct-0531-Oct-05

13-Nov-05

1-Dec-05

15-Dec-0531-Dec-05

Date

Million Cubic Feet of Gas Per Day

0

10

20

30

40

50

60

70

80

Deepwater Percent of Total Gas Shut In

GOM gas shut in

Deepwater gas shut in

Deepwater percent of total GOM gas shut in

Figure 69b. Comparison of total GOM gas shut in and GOM deepwater gas shut in. 
95 

SUMMARY AND CONCLUSIONS 

This report has discussed 

• significant new discoveries that are expanding large new geologic plays; 

• technological innovations and new concepts (e.g., hydrate potential, impact of loop 

currents, LNG terminals, and HIPPS) that may have significant effects on the energy 

outlook of the GOM; 

• technological challenges such as the HPHT drilling environment; 

• sustained deepwater leasing activity; 

• deepwater leaseholdings of major oil and gas companies compared with nonmajor 

companies, showing the increased presence of nonmajor companies; 

• future deepwater lease availability and anticipated lease expirations; 

• declines in deepwater drilling; 

• the progression of exploration activities, and the resulting discoveries, into the ultradeep frontier; 

• the extension of development activities and infrastructure, which include subsea 

wells, hubs, and pipelines reaching into ever deeper waters; 

• the anticipated large deepwater reserve additions, especially when unproved reserves, 

known resources, and recent industry-announced discoveries are considered; 

• the large increase in average deepwater field sizes when compared with same-year 

shallow-water discoveries; and 

• production rates of deepwater wells exceeding those of shallow-water wells by 800 

to 2,400 percent. 

The remainder of this report combines historic leasing, drilling, development, reserve, and production 

data, revealing overall trends in deepwater activity and expectations. 

Figure 70 illustrates deepwater projects that began production in 2004 and 2005 and those expected to 

commence production in the next six years. Sixteen deepwater projects went online in 2004 and another 

six in 2005. As of March 2006, six additional projects began production, with another four projects 

expected to go online by yearend. In addition to the projects shown in figure 70, many more are likely to 

come online in the next few years but are not shown because operators have not yet announced their 

plans. 

DEVELOPMENT CYCLE

There was considerable lease activity in the late 1980’s (figure 71). (Note that historic deepwater leasing 

shows no clear relation to average oil or gas prices.) Acreage at Auger (Garden Banks Block 426) was 

acquired in 1985 as part of this early activity. The first Auger well was drilled soon after, in 1987. Even 

though Auger was leased and drilled early, first production did not begin until 1994, approximately 

10 years after the initial lease acquisition. Acreage at Thunder Horse (Mississippi Canyon Block 778) 

was acquired in 1988; however, the discovery was not drilled until 1999, and production is not anticipated 

until later this year. This large gap highlights the considerable lag between leasing and first production. 

These lags are not unusual with complex deepwater developments. In contrast, other deepwater projects, 
96



  

  



 

 

  











 



  

 













 















	



  



	 
			 
 
 
 

 	





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	%




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(  	

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#

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Figure 70. Deepwater projects that began production in 2004 and 2005 and those expected to begin production by y
97

30

201

539

332

863

405

102

395

2,075

1,002

696

773 

4 11 32 0

500

1,0001,5002,0002,500

1974-75 1976-77 1978-79 1980-81 1982-83 1984-85 1986-87 1988-89 1990-91 1992-93 1994-95 1996-97 1998-99 2000-01 2002-0

Year Lease Sale

Number of Leases

Number of leasesAverage U.S. oil priceAverage U.S. natural gas price (wellhead)

Auger leased (1985)

1st Auger well (1987)

Thunder Horse leased (1988)

1st Auger production (1994) .

1st Thunder Horse well (1999) .

1st Typhoon production (2001) .

Typhoon leased (1995

)

1st Typhoon well (1998)

Figure 71. Deepwater lease activity and oil/natural gas prices (prices from U.S. Energy Information Administrat

December 2005 and natural gas through October 2005). 
98 

such as Typhoon (Green Canyon Block 237) and Constitution (Green Canyon Block 680), have achieved 

much shorter cycle times. ChevronTexaco acquired acreage at Typhoon in 1995, drilled the first well in 

1998, and began producing the field in 2001. Similarly, acreage at Constitution was acquired in 2001, the 

first well was drilled that same year, and production began in 2006. These shortened cycle times result 

from an accessible infrastructure and the use of proven development technologies. 

Deepwater leasing activity accelerated in the late 1990’s after Congress enacted the Deep Water Royalty 

Relief Act. The 3,000 leases that were issued during the record sales from 1996 to 1998 are expiring or 

nearing the end of their primary terms and, therefore, operators are facing key decisions about which 

leases to relinquish untested. Drilling activities are just beginning to prove the potential of these leases. 

There is a significant interval from lease acquisition to first production; however, this interval has 

decreased from 10 to less than 7 years. Figure 72 demonstrates average lags associated with deepwater 

operations. The figure uses data from only productive deepwater leases and illustrates the lags between 

leasing and qualification and from qualification to first production. Operators sometimes announce 

discoveries to the public long before qualifying the lease as productive with MMS (and thereby granted 

field status). Note that, since deepwater leases are in effect for 8 or 10 years, the data are incomplete 

beyond 1995. The apparent decreasing lags for leases issued after 1995 are explained by the fact that the 

lease evaluation process has not yet been completed. 

The data show an increase from 1976 to 1989 in the number of years before the first well is drilled. This 

is probably a reflection of two factors. First, the earliest deepwater leases purchased were of very high 

interest to the lessees and, therefore, were drilled quickly. Second, increasing lease inventories during the 

late 1980’s meant that many leases could not be evaluated early in their lease terms (increased deepwater 

leasing in the mid- to late 1980’s was probably related to the introduction of area-wide leasing, the drop 

in minimum required bid from $150/acre to $25/acre, and the advent of 3-D seismic technology). During 

the 1980’s there was a gradual increase in the lag between drilling the first well and qualifying the lease. 

During most of the 1980’s, it took 10 to 11 years for the average field to come on production. It is 

important to note, however, that the time between drilling the first well and the beginning of production 

dropped significantly in the late 1980’s. The most recent complete data (many leases issued after 1995 

are still in their primary terms) indicate that, since 1989, the time from lease to first production has 

decreased from over 11 to less than 7 years. 

In summary, the latest complete data indicate a three-year average lag between leasing and initial drilling. 

There is an additional two-year average lag before the well is qualified, and a total of less than 7 years 

from lease issuance until production begins. 

Another interesting trend is shown in figure 73. For any given lease-sale year, 43 percent of tested leases 

were first drilled within three years of lease acquisition, and 23 percent were drilled in year eight or later. 

Eighteen percent of the hydrocarbon volumes were discovered during the first three years of their lease 

terms, but 47 percent of the hydrocarbon volumes were discovered in year eight or later. The data for this 

analysis include only deepwater leases acquired through 1995, since later leases are still within their 

primary terms. 

As expected, the majority of wells are drilled in the first half of a lease’s primary term. What is surprising 

is the amount of major discoveries found in the later years of some leases’ terms — two-thirds of 

hydrocarbons discovered. For example, the discoveries of Thunder Horse, North Thunder Horse, 

Holstein, and Atlantis occurred late in their lease terms. This fact demonstrates the difficulty in 

recognizing, or perhaps drilling, the best prospects at the beginning of a lease’s term. 
99

2.67

0.29

1.14 0.72

4.78

5.45

6.34 6.55

5.47

3.45 3.46

2.7 2.38

0.96 

1.75

2.76

3.58

0.94

1.64

1.74

3.88

1.87

0.82

1.09

1.81

1.21 1.46

0.49 

7.02

3.42

2.37 8.53

5.5

4.81

4.57

3.29

1.84

1.35

1.2

1.63

0.97

1.62

02468

10121416

1974-75 1976-77 1978-79 1980-81 1982-83 1984-85 1986-87 1988-89 1990-91 1992-93 1994-95 1996-97 1998-99 2000-01 

Year Lease Acquired

Number of Years

Additional time to first productionAdditional time to qualifyYears to first well

leases in primary 

Figure 72. Lag from leasing to first production for producing deepwater fields. 
100

20

15

12

7

4

4

1

1

1

1

8

4

3

8 8

0

200400600800

1,0001,2001,4001,6001,800

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 

Year of Lease Term

Million BOE Discovered

Reserves & resourcePercent wells drilled

includes Atlantis and Holstein

includes Thunder Horse

Figure 73. Year in the lease term in which BOE was discovered and percent of leases were tested, for deepwa

1995. 
101 

DRILLING THE LEASE INVENTORY

The combination of huge deepwater lease inventories and a limited rig fleet dedicated to the GOM means 

that the vast majority of today’s leases may remain untested when their terms expire. Figure 74 shows 

historic lease activity trends. As mentioned previously, these data are complete only through 1995, since 

most deepwater leases beyond that time are still under their primary terms and still under evaluation. 

Similar to today’s large lease inventory was the period 1988 to 1989, during which large numbers of new 

leases were acquired. The percentage of leases drilled decreased as lease inventory swelled because of a 

limited number of available rigs. During times of high lease inventory, fewer than 10 percent of 

deepwater leases were drilled and fewer than 5 percent were produced. 

Exploratory drilling is arguably the most important indicator of exploration effort. Figure 75 uses the 

number of newly drilled leases as the measure of this effort. The general relationship between 

exploration effort and amount of hydrocarbons discovered is shown in figure 75. The amount discovered 

includes reserves, resources, and industry-announced discoveries (same data as figure 57). Notice that, in 

the last two years, there has been a decline in the number of new leases tested, but an increase in 2005 in 

barrels found. It is important to recognize that volumes discovered in 2004 and 2005 are significantly 

understated because of the 24-month delay in industry’s release of proprietary drilling results. 

Although the percentage of leases drilled decreased during the late 1980’s, the actual number of leases 

issued and drilled generally increased, resulting in higher numbers of discoveries and producing leases. 

These relationships among leasing, drilling, and production of offshore deepwater blocks are shown in 

figures 76a-c. There is only a general correlation between the number of leases issued and those drilled 

and produced (figures 76a-b). In contrast, the number of deepwater leases drilled correlates strongly with 

the number of those leases that later produced (figure 76c). 

Figure 77 illustrates the magnitude of the deepwater lease inventory and industry’s ability to evaluate this 

large number of leases. The annual historic lease data from 1984 through 2005 are indicated by the solid 

colored lines and depict the number of primary term leases, number of leases tested, and the number of 

leases expiring untested. The large increase in lease inventory from 1996 through 2002 is very evident 

and propagates through to 2012. Future values for primary term leases, lease expirations, and leases 

drilled are in the dotted lines. These values assume that, after the year 2006, all leases will expire unless 

drilled and that 60 untested deepwater leases will be drilled each year. 

A historic review of GOM exploration activity indicates that, on average, about 10 percent of the 

deepwater leases acquired in the large sales are drilled. Of the approximately 3,300 deepwater leases 

issued from 1996 through 2000, however, less than 8 percent have been drilled to date. There are over 

2,000 leases from these sales still in their primary lease term, with more than 630 of these leases in water 

depths of greater than 7,000 ft (2,134 m). Only 39 wells have been drilled on the ultra-deepwater leases 

from these sales; 14 of these wells resulted in announced discoveries. Figure 77 projects a steep decline 

in active leases as the large number of leases acquired in 1996 through 1998 start to expire. Note that this 

graph does not include the hundreds of new leases that will be added to the inventory each year from 

upcoming lease sales. The available deepwater rig fleet will challenge industry’s ability to evaluate their 

lease inventory, both current and future additions. Other factors play a significant role in the industry’s 

ability to evaluate their GOM lease inventory, including alternative deepwater exploration and 

development targets throughout the world, capital limitations, and limited qualified personnel. 
102

201

539

332

863

405

102

395

2,075

1,002

32 4 11 30

696

773 

0

102030405060708090

100

1974-75 1976-77 1978-79 1980-81 1982-83 1984-85 1986-87 1988-89 1990-91 1992-93 1994-95 1996-97 1998-99 2000-01 2002-03 

Year Lease Sale

Percent of Leases with Activity

Percent leases drilled Percent leases productiveNumber of leases acquired

leases in primary ter

Figure 74. Activity on deepwater leases. 
103

0

1020304050607080

1974

1976

1978

1980

1982

1984

1986

1988

1990

1992

1994

1996

1998

2000

2002

2004

Year

Number of Leases Drilled

Number of leases drilledTotal deepwater MMBOE discovered

Figure 75. Leases drilled and barrels found. 
104 

0

200

400

600

0 10 20 30 40 50 60 70 80 90 100

Number of Leases Drilled

Number of Leases Issued

Figure 76a. Relationship between number of leases issued and number of leases drilled, 

1974-1995. 

0

200

400

600

0 5 10 15 20 25 30

Number of Producing Leases

Number of Leases Issued

Figure 76b. Relationship between number of leases issued and number of resulting 

producing leases, 1974-1995. 

0

50

100

0 5 10 15 20 25 30

Number of Producing Leases

Number of Leases Drilled

Figure 76c. Relationship between number of leases drilled and number of resulting producing 

leases, 1974-1995. 
105 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

198519861987198819891990199119921993199419951996199719981999200020012002200320042005200620072008200920102011201220132014

Year

Number of Leases

Leases tested

Leases expiring

Leases in primary term

Figure 77. The challenge of deepwater lease evaluation. 

EXPANDING FRONTIER

It is instructive to look back to the earlier deepwater reports (figure 78) and observe the dramatic 

increases in proved reserves and discovered volumes (which include proved and unproved reserves, 

resources, and industry-announced discoveries). Many of the discovered volumes in earlier reports have 

progressed to become proved reserves in subsequent reports. For example, in the 2002 report, Thunder 

Horse was in the discovered-volumes category, and in the 2004 report its volumes were classified as 

proved reserves. While proved reserves and discovered volumes have substantially increased from report 

to report, the most dramatic increases have occurred in the discovered volumes, suggesting a bright 

outlook for future deepwater production, as the less constrained resource and industry-announced 

volumes move into the reserve category and are produced. 

The future of deepwater GOM exploration and production remains very promising. As shown in 

figure 77, industry is nearing the end of the primary lease term of the exceptional number of leases 

acquired in 1996 through 1998. Traditional deepwater minibasin plays are far from mature, as several 

recent discoveries attest, and new deepwater plays near and even beyond the Sigsbee Escarpment, beneath 

thick salt canopies, and in lightly explored Paleogene reservoirs show that the deepwater GOM is an 

expanding frontier. The 2000 Assessment indicated that more than 50 billion recoverable BOE remained 

to be discovered (Lore et al., 2001). 
106 

2000 2002 2004 2006

8,622

12,781

15,573

18,531

4,015 4,385

6,702

9,435

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

Million Barrels of Oil Equivalent

Year of Report

Proved reservees

Proved and unproved reserves + resources + industryannounced discoveries

Figure 78. Comparison of 2000, 2002, 2004, and 2006 deepwater GOM reports: successive increases 

in deepwater BOE. 

The deepwater arena has made great strides in the last few years, establishing itself as an expanding 

frontier. The previous edition of this report (Richardson et al., 2004) documented the advancements made 

in deepwater exploration and development since 1974. Several notable changes have occurred in the 

deepwater GOM since the 2004 report. 

Highlights 

• The deepwater frontier is expanding in water depths greater than 7,000 ft (2,134 m). 

• The deepest well in the GOM was drilled by Chevron/Unocal at the Knotty Head 

discovery to a TVD of 34,157 ft (10,411 m) and in a water depth of 3,557 ft (1,084 

m). 

• Nine discoveries were found in over 7,000-ft (2,134-m) water depths. 

• The first cell spar was installed at Red Hawk. 

• Four discoveries were made in the Eastern GOM. 

• Four discoveries were made in Paleogene reservoirs in Walker Ridge and Alaminos 

Canyon. 

• Newly collected loop-current data will promote technological developments to ensure 

safe, reliable drilling and production. 
107 

• Wells are moving into more high-temperature, high-pressure (HPHT) environments. 

• Technologies such as high integrity pressure protection systems (HIPPS) will enable 

development in deeper waters and harsher environments. 

• The number of completed subsea wells is down 15 percent. 

• There was nearly a 190-percent increase in the number of pipelines less than or equal 

to 12 inches approved for installation. 

• There was a 38-percent increase in the number of producing deepwater projects. 

• Nonmajor companies have made more deepwater discoveries and hold more 

deepwater acreage than the major companies. 

• Subsea gas production increased more than 110 percent between December 2000 and 

May 2004. 

Since the beginning of 2000, new deepwater drilling added over 6.2 billion BOE, a 50-percent increase 

over the total deepwater BOE discovered from 1974 to 1999. 

The deepwater GOM continues to increase in its importance to the Nation’s energy supply. The large 

number of active deepwater leases, the drilling of important new discoveries, the growing deepwater 

infrastructure, and the increasing deepwater production — all are indicators of the expanding frontier, 

ensuring that the deepwater GOM will remain one of the world’s premier oil and gas basins. 
109 

CONTRIBUTING PERSONNEL 

This report includes contributions from the following individuals: 

Pat Adkins 

Alex Alvarado 

Richie Baud 

Patricia Bryars 

Mike Conner 

Michael Dorner 

Fred Hefren 

Michael LaFleur 

Alexis Lugo-Fernandez 

Jason Mathews 

Deborah Miller 

Robert Peterson 

Michael Prendergast 

Michael Smith 

Sean Verret 
111 

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113 

APPENDICES 

APPENDIX A. ANNOUNCED DEEPWATER DISCOVERIES 

 (SORTED BY PROJECT NAME1

).

Project Name Area/Block 

Water 

Depth 

(ft)2 Field 

Field 

Discovery 

Date3

Year of 

First 

Production 

Year of 

Last 

Production 

Aconcagua MC 305 7,100 MC 305 2/21/1999 2002 

Alabaster MC 485 1,438 MC 397 8/27/1982 1992 

Allegheny GC 254 3,294 GC 254 1/01/1985 1999 

Amberjack MC 109 1,100 MC 109 11/13/1983 1991 

Anduin MC 755 2,904 

Angus GC 112 2,045 GC 112 6/08/1997 1999 

Ariel/Na Kika MC 429 6,240 MC 429 11/20/1995 2004 

Arnold EW 963 1,800 EW 963 6/12/1996 1998 

Aspen GC 243 3,065 GC 243 1/27/2001 2002 

Atlantis GC 699 6,133 5/12/1998 

Atlas LL 50 8,934 

Atlas NW LL 5 8,810 

Auger GB 426 2,860 GB 426 5/01/1987 1994 

Baha AC 600 7,620 AC 600 5/23/1996 

Balboa EB 597 3,352 EB 597 7/02/2001 

Baldpate GB 260 1,648 GB 260 11/01/1991 1998 

Big Foot WR 29 5,286 

Bison GC 166 2,381 GC 166 3/01/1986 

Black Widow EW 966 1,850 EW 921 5/01/1986 2000 

Blind Faith MC 696 6,989 

Boomvang East EB 668 3,650 EB 668 9/12/2003 2003 

Boomvang North EB 643 3,650 EB 643 12/13/1997 2002 

Boomvang West EB 643 3,650 EB 643 12/13/1997 2003 

Boris GC 282 2,378 GC 282 9/29/2001 2003 

Brutus GC 158 3,300 GC 158 3/01/1989 2001 

Bullwinkle GC 65 1,353 GC 065 10/01/1983 1989 

Camden Hills MC 348 7,216 MC 348 8/04/1999 2002 

Cascade WR 206 8,143 

Champlain AT 63 4,457 AT 063 2/11/2000 

Cheyenne LL 399 8,987 

Chinook WR 469 8,831 

Citrine GC 157 2,614 GC 158 5/14/1998 2005 

Clipper GC 299 3,452 
114 

Project Name Area/Block 

Water 

Depth 

(ft)2 Field 

Field 

Discovery 

Date3

Year of 

First 

Production 

Year of 

Last 

Production 

Cognac MC 195 1,023 MC 194 7/01/1975 1979 

Conger GB 215 1,500 GB 260 11/01/1991 2000 

Constitution GC 680 5,071 10/31/2001 2006 

Cooper GB 388 2,600 GB 388 3/16/1989 1995 1999 

Coulomb/Na Kika MC 657 7,591 MC 657 11/01/1987 2004 

Crested Butte GC 242 2,846 

Crosby MC 899 4,400 MC 899 1/04/1998 2001 

Cyclops AT 8 3,135 AT 008 4/26/1997 

Dawson GB 669 3,152 GB 668 5/22/2000 2003 

Dawson Deep GB 625 2,900 GB 668 5/22/2000 

Devil's Tower MC 773 5,610 MC 773 12/13/1999 2004 

Diamond MC 445 2,095 MC 445 12/05/1992 1993 1999 

Diana EB 945 4,500 EB 945 8/01/1990 2000 

Diana South AC 65 4,852 AC 065 3/24/1997 2004 

Dionysus VK 864 1,508 VK 864 10/01/1981 

Dulcimer GB 367 1,120 GB 367 2/09/1998 1999 

Durango GB 667 3,105 GB 668 5/22/2000 2003 

East Anstey/ 

Na Kika MC 607 6,590 MC 607 11/12/1997 2003 

EB 377 EB 377 2,450 EB 377 10/01/1985 

Einset VK 872 3,500 VK 873 3/01/1988 2001 

El Toro GC 69 1,465 GC 069 9/13/1984 

Entrada GB 782 4,690 

Europa MC 935 3,870 MC 935 4/22/1994 2000 

EW 1006 EW 1006 1,884 EW 1006 1/26/1988 1999 

EW 878 EW 878 1,585 EW 878 7/03/2000 2001 

Falcon EB 579 3,638 EB 579 9/29/2002 2003 

Fourier/Na Kika MC 522 6,950 MC 522 7/01/1989 2003 

Front Runner GC 338 3,330 GC 339 6/08/2001 2004 

Fuji GC 506 4,262 GC 506 1/30/1995 

GB 208 GB 208 1,275 GB 208 9/01/1991 

GB 244 GB 244 2,130 GB 244 8/15/2001 

GB 302 GB 302 2,411 GB 302 2/01/1991 

GB 379 GB 379 2,076 GB 379 7/01/1985 

GC 137 GC 137 1,168 2/16/2004 2005 

GC 147 GC 147 1,275 GC 147 5/01/1988 

GC 162 GC 162 2,616 GC 162 7/01/1989 
115 

Project Name Area/Block 

Water 

Depth 

(ft)2 Field 

Field 

Discovery 

Date3

Year of 

First 

Production 

Year of 

Last 

Production 

GC 21 GC 21 1,296 GC 021 10/01/1984 

GC 228 GC 228 1,950 GC 228 7/01/1985 

GC 27 GC 27 1,593 GC 027 7/01/1989 

GC 29 GC 29 1,554 GC 029 1/01/1984 1988 1990 

GC 31 GC 31 2,243 GC 075 5/01/1985 1988 1989 

GC 39 GC 39 2,068 GC 039 4/01/1984 

GC 463 GC 463 4,032 GC 463 12/01/1998 

GC 70 GC 70 1,618 GC 070 6/01/1984 

Gemini MC 292 3,393 MC 292 9/07/1995 1999 

Genesis GC 205 2,590 GC 205 9/01/1988 1999 

Genghis Khan GC 652 4,300 

Glider GC 248 3,440 12/19/1996 2004 

Goldfinger MC 771 5,423 2005 

Gomez MC 711 3,098 MC 755 3/19/1986 2006 

Goose MC 751 1,624 MC 751 12/15/2002 

Grand Canyon GC 141 1,720 

Great White AC 857 8,717 

Gretchen GC 114 2,685 GC 114 12/18/1999 

Gunnison GB 668 3,100 GB 668 5/22/2000 2003 

Habanero GB 341 2,015 GB 387 10/03/1994 2003 

Hack Wilson EB 598 3,650 EB 643 12/13/1997 2004 

Harrier EB 759 4,114 EB 759 1/28/2003 

Hawkes MC 509 4,174 MC 509 11/20/2001 

Herschel/Na Kika MC 520 6,739 MC 522 7/01/1989 2003 

Holstein GC 645 4,344 GC 644 2/11/1999 2004 

Hoover AC 25 4,825 AC 025 1/30/1997 2000 

Horn Mountain MC 127 5,400 MC 084 1/01/1993 2002 

Hornet GC 379 2,076 GC 379 12/14/2001 

Ida/Fastball VK 1003 4,942 

Jack WR 759 6,965 

Jolliet GC 184 1,760 GC 184 7/01/1981 1989 

Jubilee AT 349 8,825 

Jubilee Extension LL 309 8,774 

K2 GC 562 4,006 GC 562 8/14/1999 2005 

K2 North GC 518 4,049 2006 

Kepler/Na Kika MC 383 5,759 MC 383 8/31/1997 2004 

King (MC-BP) MC 84 5,000 MC 084 1/01/1993 2002 
116 

Project Name Area/Block 

Water 

Depth 

(ft)2 Field 

Field 

Discovery 

Date3

Year of 

First 

Production 

Year of 

Last 

Production 

King (MC-Shell) MC 764 3,250 MC 807 4/01/1989 2000 

King Kong GC 472 3,980 GC 472 2/01/1989 2002 

King's Peak DC 133 6,845 DC 133 3/01/1993 2002 

Knotty Head GC 512 3,557 

Ladybug GB 409 1,355 GB 409 5/13/1997 2001 

La Femme MC 427 5,800 

Lena MC 280 1,000 MC 281 5/01/1976 1984 

Leo MC 546 2,505 MC 546 2/01/1986 

Llano GB 386 2,663 GB 387 10/03/1994 2004 

Lorien GC 199 2,315 

Lost Ark EB 421 2,960 EB 421 1/31/2001 2002 

Macaroni GB 602 3,600 GB 602 1/21/1996 1999 

Mad Dog GC 782 4,428 GC 826 11/24/1998 2005 

Madison AC 24 4,856 AC 024 6/25/1998 2002 

Magnolia GB 783 4,674 GB 783 5/03/1999 2004 

Manatee GC 155 1,939 GC 110 8/07/1987 2002 

Marathon GC 153 1,618 GC 153 4/01/1984 

Marco Polo GC 608 4,320 GC 608 4/21/2000 2004 

Marlin VK 915 3,236 VK 915 6/01/1993 2000 

Mars MC 807 2,933 MC 807 4/01/1989 1996 

Marshall EB 949 4,376 EB 949 7/30/1998 2001 

Matterhorn MC 243 2,850 MC 243 9/01/1990 2003 

MC 113 MC 113 1,986 MC 113 1/01/1976 

MC 285 MC 285 3,161 MC 285 9/01/1987 

MC 455 MC 455 1,400 MC 455 2/01/1986 

MC 68 MC 68 1,360 MC 068 12/09/1975 2001 

MC 709 MC 709 2,599 MC 709 2/01/1987 

MC 837 MC 837 1,524 EW 878 7/03/2000 

MC 929 MC 929 2,250 MC 929 11/01/1987 

McKinley GC 416 4,019 GC 416 7/14/1998 

Medusa MC 582 2,223 MC 582 10/10/1998 2003 

Medusa North MC 538 2,223 MC 582 10/10/1998 2003 

Mensa MC 731 5,318 MC 731 12/01/1986 1997 

Merganser AT 37 8,015 AT 037 11/28/2001 

Mica MC 211 4,580 MC 211 5/01/1990 2001 

Mighty Joe Young GC 737 4,415 

Mirage MC 941 3,927 MC 899 1/04/1998 
117 

Project Name Area/Block 

Water 

Depth 

(ft)2 Field 

Field 

Discovery 

Date3

Year of 

First 

Production 

Year of 

Last 

Production 

Moccasin GB 254 1,920 GB 254 7/23/1993 

Mondo Northwest LL 2 8,340 

Mondo NW Ext. LL 1 8,340 

Morgus MC 942 3,960 MC 899 1/04/1998 

Morpeth EW 921 1,696 EW 921 5/01/1986 1998 

Mosquito Hawk GB 269 1,102 GB 269 3/06/1996 

Nansen EB 602 3,675 EB 602 9/25/1999 2002 

Navajo EB 690 4,210 EB 602 9/25/1999 2002 

Navarro GC 37 2,019 

Neptune(AT-BHP) AT 575 6,220 AT 575 9/26/1995 

Neptune 

(VK-Kerr-McGee) VK 826 1,930 VK 825 11/01/1987 1997 

Ness GC 507 3,947 GC 507 12/27/2001 

Nile VK 914 3,535 VK 914 4/30/1997 2001 

Nirvana MC 162 3,724 MC 162 11/30/1994 

Northwestern GB 200 1,736 GB 200 5/14/1998 2000 

Oregano GB 559 3,400 GB 559 3/27/1999 2001 

Oyster EW 917 1,195 EW 873 12/01/1985 1998 

Pardner MC 401 1,139 WD 152 10/01/19684 2003 

Penn State GB 216 1,450 GB 260 11/01/1991 1999 

Petronius VK 786 1,753 VK 786 7/14/1995 2000 

PI 525 PI 525 3,430 PI 525 4/30/1996 

Pilsner EB 205 1,108 EB 205 5/02/2001 2001 

Pluto MC 674 2,828 MC 718 10/20/1995 1999 

Pompano VK 990 1,290 VK 990 5/01/1981 1994 

Popeye GC 116 2,000 GC 116 2/01/1985 1996 

Poseidon (GC) GC 691 4,489 GC 691 2/27/1996 

Poseidon (MC) MC 772 5,567 MC 728 6/30/2002 2005 

Prince EW 1003 1,500 EW 958 7/20/1994 2001 

Princess MC 765 3,600 MC 807 4/01/1989 2002 

Ptolemy GB 412 1,322 GB 412 7/01/1984 

Puma GC 823 4,129 

Q MC 961 7,925 

Ram-Powell VK 956 3,216 VK 956 5/01/1985 1997 

Raptor EB 668 3,710 EB 668 9/13/2003 2004 

Red Hawk GB 877 5,334 GB 877 10/18/2001 2004 

Rigel MC 252 5,229 MC 252 11/29/1999 2006 
118 

Project Name Area/Block 

Water 

Depth 

(ft)2 Field 

Field 

Discovery 

Date3

Year of 

First 

Production 

Year of 

Last 

Production 

Rockefeller EB 992 4,872 EB 992 11/28/1995 

Rocky GC 110 1,785 GC 110 8/07/1987 1996 

San Jacinto DC 618 7,850 

San Patricio AT 153 4,785 AT 153 8/09/2001 

Sangria GC 177 1,487 GC 177 8/22/1999 2002 

Serrano GB 516 3,153 GB 516 7/23/1996 2001 

Seventeen Hands MC 299 5,881 MC 299 5/04/2001 2006 

Shasta GC 136 1,048 GC 136 7/01/1981 1995 

Shenzi GC 653 4,238 

Silvertip AC 815 9,226 

Spiderman DC 621 8,087 

St. Malo WR 678 7,036 

Stones WR 508 9,556 

Sturgis AT 183 3,710 

Supertramp MC 26 1,272 MC 026 5/27/1994 

SW Horseshoe EB 430 2,285 EB 430 5/03/2000 

Swordfish VK 962 4,677 VK962 11/15/2001 2005 

Tahiti GC 640 4,292 

Tahoe VK 783 1,500 VK 783 12/01/1984 1994 

Thunder Hawk MC 734 5,724 

Thunder Horse MC 778 6,050 MC 778 4/01/1999 

Thunder Horse 

North MC 776 5,660 

Ticonderoga GC 768 5,272 10/03/2004 2006 

Tiger AC 818 9,004 

Timber Wolf MC 555 4,749 MC 555 10/30/2001 

Tobago AC 859 9,627 

Tomahawk EB 623 4,114 EB 579 1/28/2003 2003 

Trident AC 903 9,743 

Triton MC 728 5,373 MC 728 6/30/2002 2005 

Troika GC 244 2,721 GC 244 5/30/1994 1997 

Tubular Bells MC 725 4,334 

Tulane GB 158 1,054 GB 200 5/14/1998 2002 

Typhoon GC 237 2,679 GC 236 10/01/1984 2001 

Ursa MC 809 3,800 MC 807 4/01/1989 1999 

Virgo VK 823 1,130 VK 823 1/01/1993 1999 

VK 862 VK 862 1,043 VK 862 10/01/1976 1995 

VK 917 VK 917 4,370 VK 917 12/08/2001 
119 

Project Name Area/Block 

Water 

Depth 

(ft)2 Field 

Field 

Discovery 

Date3

Year of 

First 

Production 

Year of 

Last 

Production 

Vortex AT 261 8,344 

Wrigley MC 506 3,700 

Yosemite GC 516 4,150 GC 472 2/01/1989 2002 

Zia MC 496 1,804 MC 582 10/10/1998 2003 

Zinc MC 354 1,478 MC 354 8/01/1977 1993 

1

 A block may be listed under more than one project name because of lease relinquishment, expiration, or termination and 

subsequent re-leasing. Some announced discoveries never reached the project stage and are listed under their prospect 

names. 2

 Water depths shown reflect depth at facility. If project is subsea or undeveloped, water depth reflects depth of deepest well 

location in project. 3

 The absence of a field discovery date indicates an industry-announced discovery without a qualified well on the lease. These

discoveries have not necessarily been confirmed by the MMS and they are not yet classified as fields by the MMS. 4 The deepwater portion of the Pardner project was discovered in 2002. 
121 

APPENDIX B. CHRONOLOGICAL LISTING OF GOM LEASE SALES BY SALE 

LOCATION AND SALE DATE. 

Sale 

Number Sale Location Sale Date 

1 LA1 10/13/1954 

1S LA 10/13/1954 

2 TX 11/09/1954 

3 TX, LA 7/12/1955 

6 LA2 8/11/1959 

7 TX, LA 2/24/1960 

8 LA3 5/19/1960 

9 LA 3/13/1962 

10 TX, LA 3/16/1962 

11 LA2 10/09/1962 

12 LA2 4/28/1964 

13 SUL-TX4 12/14/1965 

14 LA2 3/29/1966 

15 LA2 10/18/1966 

16 LA 6/13/1967 

17 SA-LA5 9/05/1967 

18 TX 5/21/1968 

19 LA2 11/19/1968 

19A LA2 1/14/1969 

20 SUL-LA6 5/13/1969 

19B LA2 12/16/1969 

21 LA2 7/21/1970 

22 LA 12/15/1970 

23 LA2 11/04/1971 

24 LA 9/12/1972 

25 LA 12/19/1972 

26 TX, LA 6/19/1973 

32 MAFLA7 12/20/1973 

33 LA 3/28/1974 

34 TX 5/29/1974 

S1 TX, LA 7/30/1974 

36 LA 10/16/1974 

37 TX 2/04/1975 

38 TX, LA 5/28/1975 

38A TX, LA 7/29/1975 

41 GOM 2/18/1976 

44 TX, LA 11/16/1976 

47 GOM 6/23/1977 

45 TX, LA 4/25/1978 

65 GOM 10/31/1978 

51 TX, LA 12/19/1978 

58 GOM 7/31/1979 

58A GOM 11/27/1979 

Sale 

Number Sale Location Sale Date 

A62 GOM 9/30/1980 

62 GOM 11/18/1980 

A66 GOM 7/21/1981 

66 GOM 10/20/1981 

67 GOM 2/09/1982 

69 GOM 11/17/1982 

69A GOM 3/08/1983 

72 CGOM 5/25/1983 

74 WGOM 8/24/1983 

79 EGOM 1/05/1984 

81 CGOM 4/24/1984 

84 WGOM 7/18/1984 

98 CGOM 5/22/1985 

102 WGOM 8/14/1985 

94 EGOM 12/18/1985 

104 CGOM 4/30/1986 

105 WGOM 8/27/1986 

110 CGOM 4/22/1987 

112 WGOM 8/12/1987 

SS CGOM 2/24/1988 

113 CGOM 3/30/1988 

115 WGOM 8/31/1988 

116 EGOM 11/16/1988 

118 CGOM 3/15/1989 

122 WGOM 8/23/1989 

123 CGOM 3/21/1990 

125 WGOM 8/22/1990 

131 CGOM 3/27/1991 

135 WGOM 8/21/1991 

139 CGOM 5/13/1992 

141 WGOM 8/19/1992 

142 CGOM 3/24/1993 

143 WGOM 9/15/1993 

147 CGOM 3/30/1994 

150 WGOM 8/17/1994 

152 CGOM 5/10/1995 

155 WGOM 9/15/1995 

157 CGOM 4/24/1996 

161 WGOM 9/25/1996 

166 CGOM 3/05/1997 

168 WGOM 8/27/1997 

169 CGOM 3/18/1998 

171 WGOM 8/26/1998 
122 

Sale 

Number Sale Location Sale Date 

172 CGOM 3/17/1999 

174 WGOM 8/25/1999 

175 CGOM 3/15/2000 

177 WGOM 8/23/2000 

178-1 CGOM 3/28/2001 

178-2 CGOM 8/22/2001 

180 WGOM 8/22/2001 

181 EGOM 12/05/2001 

182 CGOM 3/20/2002 

184 WGOM 8/21/2002 

185 CGOM 3/19/2003 

Sale 

Number Sale Location Sale Date 

187 WGOM 8/20/2003 

189 EGOM 12/10/2003 

190 CGOM 3/17/2004 

192 WGOM 8/18/2004 

194 CGOM 3/16/2005 

196 WGOM 8/17/2005 

197 EGOM 3/16/2005 

198 CGOM 3/15/2006 

200 WGOM 

201 CGOM 

1 Sale 1 was an oil, gas, and sulfur lease sale offshore Louisiana. 2 These were oil and gas drainage lease sales offshore Louisiana. 3 Sale 8 was a salt lease sale offshore Louisiana. 

4 Sale 13 was a sulfur and salt lease sale offshore Texas. 

5 Sale 17 was a salt lease sale offshore Louisiana. 

6 Sale 20 was a sulfur and salt lease sale offshore Louisiana. 

7 Sale 32 was an oil and gas lease sale offshore Mississippi, Alabama, and Florida. 

LA = oil and gas lease sale offshore Louisiana (unless otherwise footnoted) 

TX = oil and gas lease sale offshore Texas 

GOM = oil and gas lease sale in the Gulf of Mexico 

CGOM = oil and gas lease sale in the Central Gulf of Mexico Planning Area 

EGOM = oil and gas lease sale in the Eastern Gulf of Mexico Planning Area 

WGOM = oil and gas lease sale in the Western Gulf of Mexico Planning Area 
123 

APPENDIX C. NTL NO. 2006-G02, SUSPENSION OF OPERATIONS BASED ON RIG 

DELAYS, LACK OF RIG AVAILABILITY AND PROCUREMENT OF LONG 

LEAD EQUIPMENT. 

UNITED STATES DEPARTMENT OF THE INTERIOR MINERALS MANAGEMENT SERVICE 

GULF OF MEXICO OCS REGION 

NTL No. 2006-G02 

Effective Date: February 10, 2006 

Expiration Date: February 28, 2008 

NOTICE TO LESSEES AND OPERATORS OF FEDERAL OIL AND GAS LEASES 

IN THE OUTER CONTINENTAL SHELF, GULF OF MEXICO OCS REGION 

Suspensions of Operations Based on Rig Delays, Lack of Rig Availability 

and Procurement of Long Lead Equipment 

This Notice to Lessees and Operators (NTL) is issued pursuant to 30 CFR 250.103 and 30 CFR 

250.175(a) to provide guidance to our existing authority for approving requests for lease or unit 

Suspensions of Operations (SOO’s) based on rig delays and to implement a temporary policy for granting 

SOO’s based on a lack of rig availability and for unanticipated time frames needed to secure long lead 

equipment such as high pressure/temperature tubulars and wellheads. 

In accordance with the Outer Continental Shelf (OCS) Lands Acts, regulations, and current policy, the 

Department expects lessees to explore and commence development within the primary term of any OCS 

lease. However, pursuant to 30 CFR 250.175(a), the Regional Supervisor may grant an SOO when 

necessary to allow you time to begin drilling or other operations when you are prevented by reasons 

beyond your control such as unexpected weather, unavoidable accidents, or drilling rig delays. In 

general, SOO’s are short in duration. 

Currently, pursuant to 30 CFR 250.175(a), an SOO may be granted to extend the term of a lease when a 

drilling rig was contracted and scheduled to begin leaseholding operations prior to the lease expiration but 

due to reasons beyond your control, the rig was delayed. When considering an SOO request based on a 

rig delay, it is expected that no other rig options are available; therefore, any delay in the rig release date 

should be short term. It is expected that you have an approved plan (e.g., EP, DPP, etc.) and an approved 

APD. Likewise, MMS may approve SOO’s when you can demonstrate that long lead equipment was 

contracted and scheduled to arrive in time to commence a lease holding operation prior the lease 

expiration date but was delayed for reasons beyond your control. In addition, any SOO request must 

include: 

(1) verification that a rig or a long lead equipment contract has been executed, 

(2) the original date before lease expiration the rig or long lead equipment was expected 

to arrive on the lease, 

(3) full details explaining the delay, 

(4) the new anticipated date for the rig or long lead equipment to arrive on location, and 

(5) the expected date operations will commence. 

In addition to the delays as described above, an SOO request may be approved under a temporary policy 

established by this NTL when you can demonstrate to MMS’s satisfaction that a timely search has 
124 

resulted in a total lack of rigs capable of drilling prior to lease expiration. In such a case, an SOO will be 

considered to allow time for the first available rig to commence operations, provided a drilling contract 

has been executed prior to lease expiration. The SOO request must include: 

(1) full details, with supporting documentation, demonstrating that a timely rig search 

was performed, 

(2) verification that a rig contract has been executed prior to lease expiration, and 

(3) the anticipated date for the rig to arrive on location and commence operations. 

Likewise, under this temporary policy, MMS may approve SOO’s when you can demonstrate that timely 

attempts to secure long lead equipment needed for the commencement of leaseholding operations prior to 

lease expiration were unsuccessful. MMS encourages you to contact our office upon learning that your 

“timely attempts” were not sufficient. In such cases, before an SOO can be granted, a contract must have 

been executed for the timely delivery of the long lead equipment and the request must include the 

expected delivery date and an explanation why such equipment will not be delivered prior to lease 

expiration. Late attempts to secure a drilling rig contract or long lead equipment will not be justification 

for an SOO approval. 

In all cases, SOO requests must be received by the MMS prior to lease expiration. Late permit filings 

(e.g., EP, APD, etc.) will not be justification for an SOO approval. 

If you have any questions, please contact Kevin J. Karl at (504)736-2632, kevin.karl@mms.gov; or 

Ronald Konecni at (504)736-2661, ronald.konecni@mms.gov. 

Paperwork Reduction Act of 1995 Statement 

The information collection referred to in this NTL is intended to provide clarification, description, or 

interpretation of requirements contained in 30 CFR 250.175, suspension of operations. The Office of 

Management and Budget (OMB) has approved the information collection requirements in these 

regulations under OMB Control Number 1010-0114. This NTL does not impose additional information 

collection requirements subject to the Paperwork Reduction Act of 1995. 

Chris C. Oynes [Original Signed] 

Regional Director 
125 

APPENDIX D. DEEPWATER STUDIES PROGRAM

All reports are available at our web sites— 

http://www.gomr.mms.gov/homepg/regulate/environ/deepenv.html.

http://www.mms.gov/tarprojectcategories/deepwate.htm

Active Studies (MMS Project Number/Study Number) 

An Analysis of the Socioeconomic Effects of OCS-Activities on Ports and Surrounding Areas in the Gulf 

of Mexico [GM-92-42-56], [19957 G] 

An Assessment of Magnetization Effects on Hydrogen Cracking for Thick Walled Pipelines [487] 

Application of Dual Gradient Technology to Top Hole Drilling [541] 

Assessing and Monitoring Industry Labor Needs [GM-98-06] [30898 G] 

Benefits and Burdens of OCS Deepwater Activities on Selected Communities and Local Public 

Institutions [GM-98-10] [30899 G] 

Characterization of Gulf of Mexico Deepwater Hard Bottom Communities with Emphasis on Lophelia 

Coral [GM-03-02] [72323] 

Characterizing Natural Gas Hydrates in the Deepwater Gulf of Mexico [461] 

Comparison of Remote Technologies to Better Assess the Location of Gas Hydrates [39076] 

Cooperative Research on Sperm Whales and Their Response to Seismic Exploration in the Gulf of 

Mexico [GM-01-04C] [85186] 

Damaged Polyester Rope--Large Scale Experiments JIP [416] 

Deep-Sea Furrows [479] 

Deep-Sea Furrows: Physical Characteristics, Mechanisms of Formation, and Associated Environmental 

Processes [73209] 

Deepwater Current Measurements at 25EN; 90EW in Mexican Territory [85309] 

Deepwater Currents at 92° W [GM-92-42-73] [16807 B] 

Deepwater Riser VIV Project—CFD Simulation of Riser VIV [481] 

Determination of Yellowfin Tuna Aggregation and Movement Patterns Near Gulf of Mexico Deepwater 

Petroleum Structures [USGS study for MMS] 

Direct Observations of Ocean Currents over the Western Slope in the Gulf of Mexico [GM-03-01b] 

[32916] 

Document and Characterize the Branching Deepwater Corals and Geology at Two Upper-Slope Sites in 

the Northeastern Gulf of Mexico [73719] 

Drilling and Completion Gaps for High Temperature and High Pressure in Deep Water [519] 

Effects of Oil and Gas Exploration and Development at Selected Continental Slope Sites in the Gulf of 

Mexico [GM-00-01] [31034 E] 

Exploratory Study of Deepwater Currents in the Gulf of Mexico [GM-01-02] [31152 B] 

Factors Affecting Petroleum Exploration and Development and Their Impacts on the Attractiveness and 

Prospectivity of the Gulf of Mexico Deepwater [39305] 
126 

Foraminiferal Communities of Bathyal and Abyssal Hydrocarbon Seeps, Northern Gulf of Mexico: A 

Taxonomic, Ecologic, and Geologic Study [GM-92-42-86] 

Gulf of Mexico Deepwater Protected Species Studies: Sperm Whale Study [15958] 

Hydrotest Alternative JIP—For Deepwater Gas Export Pipelines [525] 

Interstitially Insulated Pipe [509] 

Investigations of Chemosynthetic Communities on the Lower Continental Slope of the Gulf of Mexico 

(Chemo III) (NOPP) [39187] 

Methodologies for Measuring and Monitoring Hydrogen for Safety in Advanced High Strength Linepipe 

Steel Applications [522] 

New Touch-Down Zone Solutions for Steel Catenary Risers [494] 

Northern Gulf of Mexico Continental Slope Habitats and Benthic Ecology [GM-99-02] [30991 C] 

Numerical Modeling of Torpedo Anchors [557] 

Observation of Deepwater Manifestation of Loop Current Rings [GM-92-42-72] [16805 B] 

OTRC Cooperative Agreement [328] 

Performance Data Base for Deepwater Production Platforms [560] 

Polyester Rope Analysis Tool [369] 

Potential Spatial and Temporal Vulnerability of Pelagic Fish Assemblages in the Gulf of Mexico to 

Surface Oil Spills Associated with Deepwater Petroleum Development [GM-92-42-61] 

Probabilistic Reliability and Integrity Assessment of Large-Diameter Compliant Risers for UltraDeepwater Operations [497] 

Regional Synthesis of the Sedimentary Thermal History and Hydrocarbon Maturation in the Deepwater 

Gulf of Mexico [432] 

Repeatability and Effectiveness of Subsurface Controlled Safety Valves [403] 

Riser VIV Workshop [521] 

Risk Assessment for Submarine Slope Stability [491} 

Risk Assessment of Surface vs. Subsurface BOP's on Mobile Offshore Drilling Units [540] 

SCR Flex Joint Design and Performance JIP [530] 

SCR Integrity Management [531] 

Seafloor Interaction with Steel Catenary Risers [510] 

Strain-Based Design of Pipelines [434] 

Survey of Deepwater Currents in the Eastern Gulf of Mexico [GM-04-01] [34269] 

Survey of Deepwater Currents in the Western Gulf of Mexico [GM-03-01] [71562] 

Technology Assessment of Alternatives for Handling Associated Gas Produced from Deepwater Oil 

Developments in the GOM [443] 

The Archaeological and Biological Analysis of World War II Shipwrecks in the Gulf of Mexico: A Pilot 

Study of the Artificial Reef Effect in Deepwater [GM-03-07] [73095] 

Understanding the Processes that Maintain the Oxygen Levels in the Deep Gulf of Mexico [GM-02-06] 
127 

Completed Reports 

Analysis and Validation of a Mechanism that Generates Strong Mid-Depth Currents and a Deep Cyclone 

Gyre in the Gulf of Mexico [31027 B]. Report Number 2004-040, Strong Mid-Depth Currents and a 

Deep Cyclonic Gyre in the Gulf of Mexico 

Assessment and Reduction of Taxonomic Error in Benthic Macrofauna Surveys: An Initial Program 

Focused on Shelf and Slope Polychaete Worms [16801 C]. Report Number 2003-065, Preparation of 

an Interactive Key for Northern Gulf of Mexico Polychaete Taxonomy Employing the DELTA/

INTKEY System 

Assessment of New and/or Improved Repair Techniques for Ageing or Damaged Structures [502] 

Assessment of Performance of Deepwater Floating Production Facilities [471] 

Bluewater Fishing and Deepwater OCS Activity: Interactions Between the Fishing and Petroleum 

Industries in Deepwaters of the Gulf of Mexico [31011 M]. Report Number 2002-078, Deepwater 

Program: Bluewater Fishing and Deepwater OCS Activity, Interactions Between the Fishing and 

Petroleum Industries in Deepwaters of the Gulf of Mexico 

Characterizing Polyester Rope Installation Damage [389] 

Cross-Shelf Exchange Processes and the Deep-Water Circulation of the Gulf of Mexico: The Dynamical 

Effects of Submarine Canyons and the Interactions of Loop Current Eddies with Topography [31029 

B]. Report Number 2004-017, Cross-Shelf Exchange Processes and the Deepwater Circulation of the 

Gulf of Mexico: Dynamical Effects of Submarine Canyons and the Interactions of Loop Current 

Eddies with Topography, Final Report 

Damage Tolerance of Synthetic-Fiber Mooring Ropes; Phase I: Small-Scale Experiments [407] 

Deep Water Anchor Reliability [362] 

Deepwater Field Measurements [417] 

Deepwater GOM Pipeline Damage Characteristics and Repair Options [532] 

Deepwater Physical Oceanography Reanalysis and Synthesis of Historical Data [30910 B]. Report 

Number 2001-064, Deepwater Physical Oceanography Reanalysis and Synthesis of Historical Data: 

Synthesis Report 

Design of Cathodic Protection Systems for Deep Water Compliant Petroleum Production Risers [496] 

Development of a Blowout Intervention Method and Dynamic Kill Simulated for Blowouts Occurring in 

Ultra-Deepwater [408] 

Evaluation of Methods of Detecting and Monitoring of Corrosion Damage in Risers [433] 

Evaluation of Secondary BOP Intervention Methods in Well Control [431] 

Experimental Validation of Well Control Procedures in Deepwater [382] 

Gulf of Mexico Deepwater Information Resources Data Search and Literature Synthesis [30916 I]. 

Report Number 2000-049, Deepwater Gulf of Mexico Environmental and Socioeconomic Data 

Search and Literature Synthesis, Volume I: Technical Narrative and Report Number 2000-050—

Deepwater Gulf of Mexico Environmental and Socioeconomic Data Search and Literature Synthesis, 

Volume II: Annotated Bibliography 

Gulf of Mexico Marine Protected Species Workshop [30665-8]. Report Number 2001-039, Gulf of 

Mexico Marine Protected Species Workshop, June 1999 

Joint Industry Project, Gulf of Mexico Comprehensive Synthetic Based Muds Monitoring Program 

[31069 E]. Gulf of Mexico Comprehensive Synthetic Based Muds Monitoring Program, Executive 

Summary, Gulf of Mexico Comprehensive Synthetic Based Muds Monitoring Program, Volumes I, 

II, and III: Appendices. 
128 

Labor Migration and the Deepwater Oil Industry [19958 G]. Report Number 2004-57, Deepwater 

Program: Labor Migration and the Deepwater Oil Industry 

Literature Review: Environmental Risks of Chemical Products Used in Deepwater Oil & Gas Operations 

[30900 E]. Report Number 2001-011, Deepwater Program: Literature Review, Environmental Risks 

of Chemical Products Used in Gulf of Mexico Deepwater Oil and Gas Operations, Volume I: 

Technical Report, and Report Number 2001-012, Deepwater Program: Literature Review, 

Environmental Risks of Chemical Products Used in Gulf of Mexico Deepwater Oil and Gas 

Operations, Volume II: Appendices 

Long Term Integrity of Deep-Water Cement Systems [426] 

Modeling and Data-Analysis of Subsurface Currents on the Northern Gulf of Mexico Slope and Rise: 

Effects of Topographic Rossby Waves and Eddy-Slope Interaction [31028 B]. Report Number 2003-

074, Modeling and Data Analyses of Circulation Processes in the Gulf of Mexico, Final Report 

OCS-Related Infrastructure in the Gulf of Mexico [30955 G]. Report Number 2004-027, OCS-Related 

Infrastructure in the Gulf of Mexico Fact Book 

Offshore Data Search and Synthesis on Highly Migratory Species in the GOM and the Effects of Large 

Fish Attracting Devices (FADs) [RD-0202]. MMS Report Number 2002-039 and USGS BSR 2002-

0005, Potential for Gulf of Mexico Deepwater Petroleum Structures to Function as Fish Aggregating 

Devices (FADs)—Scientific Information Summary and Bibliography 

Offshore Petroleum Platforms: Functional Significance for Larval Fish Across Longitudinal and 

Latitudinal Gradients [19961 M]. Report Number 2002-078, Offshore Petroleum Platforms: 

Functional Significance for Larval Fish Across Longitudinal and Latitudinal Gradients 

Potential Spatial and Temporal Vulnerability of Pelagic Fish Assemblages in the Gulf of Mexico to 

Surface Oil Spills Associated with Deepwater Petroleum Development [19962 M]. Report Number 

2005-012, Potential Spatial and Temporal Vulnerability of Pelagic Fish Assemblages in the Gulf of 

Mexico to Surface Oil Spills Associated with Deepwater Petroleum Development 

Project Offshore Deep Slopes (PODS)Phase II [472] 

Project Offshore Deep Slopes (PODS): Seafloor Stability on the Continental Shelf/Slope [404] 

Reliability Analysis of Deepwater Anchors [437] 

Reliability of Pressure Signals In Offshore Pipelines Leak Detection [398] 

Risk-Extend Comparative Risk Assessment (CRA) for a SPAR-Based FPSO [418] 

ROV/AUV Capabilities [446] 

Study of Subsurface, High-Speed Current Jets in the Deep Water Region of the Gulf of Mexico [31026 

B]. Report Number 2004-022, Deepwater Program: Subsurface, High-Speed Current Jets in the 

Deepwater Region of the Gulf of Mexico 

Summary of the Northern Gulf of Mexico Continental Slope Studies [17037 C]. Report Number 2003-

072, Selected Aspects of the Ecology of the Continental Slope Fauna of the Gulf of Mexico: A 

Synopsis of the Northern Gulf of Mexico Continental Slope Study, 1983-1988 

Supply Logistics of OCS Oil and Gas Development in the Gulf of Mexico—Evaluation of Technological 

and Economic Parameters of Ports as Supply and Manufacturing Bases [31154 G]. Report Number 

2004-047, Supply Network for Deepwater Oil and Gas Development in the Gulf of Mexico: An 

Empirical Analysis of Demand for Port Services 

The Fate and Effects of Synthetic-Based Drilling Fluids and Associated Cuttings Discharged into the 

Marine Environment [15240E]. Report Number 2000-064, Environmental Impacts of SyntheticBased Drilling Fluids 

Understanding the Processes that Maintain the Oxygen Levels in the Deep Gulf of Mexico [85080]. 

Report Number 2205-032, Understanding the Processes that Maintain the Oxygen Levels in the Deep 

Gulf of Mexico, Synthesis Report 
129 

Workshop on Deepwater Environmental Studies Strategy: A Five Year Follow-up and Planning for the 

Future [85035]. Report Number 2003-030, Workshop on Deepwater Environmental Studies Strategy: 

A Five-Year Follow-Up and Planning for the Future 

World Wide Assessment of Industry Leak Detection Capabilities for Single and Multiphase Pipelines 

[409] 

Study in the Procurement Process 

Synthetic-based Fluid Spill of Opportunity: Environmental Impact and Recovery 
131 

APPENDIX E. SUBSEA COMPLETIONS. 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

AC 24 608054000501 Exxon Mobil Corporation 2/03/2002 4,856

AC 65 608054000302 Exxon Mobil Corporation 12/31/2003 4,852

BA A 17 427044034500 Spinnaker Exploration Company LLC 8/10/2003 140

DC 133 608234000200 ATP Oil & Gas Corporation 10/15/2001 6,376

EB 112 608044015700 Eni Petroleum Co Inc 5/01/1996 638

EB 117 608044016102 Apache Corporation 4/11/1996 570

EB 157 608044015200 Eni Petroleum Co Inc 5/23/1996 941

EB 161 608044022600 Union Oil Company of California 7/23/2001 1,107

EB 168 608044023000 Walter Oil & Gas Corporation 12/15/2001 500

EB 205 608044021800 Union Oil Company of California 6/01/2001 1,081

EB 421 608044020000 Noble Energy Inc 5/12/2002 2,740

EB 430 608044019202 Walter Oil & Gas Corporation 3/13/2005 2,285

EB 579 608044023500 Pioneer Natural Resources USA Inc 11/18/2002 3,453

EB 602 608044019001 Kerr-McGee Oil & Gas Corporation 7/15/2001 3,678

EB 602 608044022000 Kerr-McGee Oil & Gas Corporation 3/06/2002 3,678

EB 623 608044023400 Pioneer Natural Resources USA Inc 12/30/2002 3,412

EB 646 608044023200 Kerr-McGee Oil & Gas Corporation 8/06/2005 3,905

EB 668 608044024101 Pioneer Natural Resources USA Inc 5/26/2005 3,710

EB 688 608044022400 Kerr-McGee Oil & Gas Corporation 12/13/2001 3,795

EB 688 608044022101 Kerr-McGee Oil & Gas Corporation 1/10/2002 3,788

EB 690 608044022801 Kerr-McGee Oil & Gas Corporation 2/18/2002 4,202

EB 759 608044022301 Pioneer Natural Resources USA Inc 11/01/2004 4,114

EB 945 608044017700 Exxon Mobil Corporation 11/20/1999 4,638

EB 945 608044016200 Exxon Mobil Corporation 3/31/2002 4,628

EB 945 608044017804 Exxon Mobil Corporation 9/25/2003 4,639

EB 946 608044018100 Exxon Mobil Corporation 3/08/2000 4,651

EB 946 608044018000 Exxon Mobil Corporation 5/31/2000 4,657

EB 948 608044017601 Exxon Mobil Corporation 5/06/2001 4,376

EB 949 608044019301 Exxon Mobil Corporation 4/02/2001 4,376

EC 57 177034047100 Houston Exploration Company 12/09/1984 52

EC 335 177044030300 Pogo Producing Company 7/15/1976 272
132 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

EC 347 177044101300 Apache Corporation 1/3/2001 291

EC 374 177044101700 Energy Resource Technology Inc 7/17/2002 425

EC 378 608074015700 El Paso Production Company 1/27/1997 495

EI 106 177094121001 Devon Louisiana Corporation 2/21/2005 40

EI 294 177104126801 B T Operating Co 10/06/1991 214

EI 349 177104100500 NCX Company LLC 11/23/1990 337

EI 386 177104147500 Tarpon Offshore LP 2/24/2002 417

EI 390 177104149001 Walter Oil & Gas Corporation 2/11/2004 377

EI 395 177104157700 Walter Oil & Gas Corporation 3/03/2004 517

EW 868 608104011501 Walter Oil & Gas Corporation 10/17/2003 685

EW 871 608104011000 Walter Oil & Gas Corporation 11/13/2000 932

EW 871 608104011300 Walter Oil & Gas Corporation 4/13/2001 724

EW 878 608105009500 Walter Oil & Gas Corporation 7/26/2000 1,523

EW 878 608105009601 Walter Oil & Gas Corporation 9/25/2000 1,523

EW 913 608104011700 Walter Oil & Gas Corporation 10/13/2004 685

EW 917 608105006500 Marathon Oil Company 4/08/1998 1,195

EW 921 608105008104 Eni Petroleum Co Inc 8/16/2002 1,692

EW 921 608105007903 Eni Petroleum Co Inc 8/16/2002 1,696

EW 921 608105009801 Eni Petroleum Co Inc 1/25/2005 1,712

EW 963 608105006000 Marathon Oil Company 5/25/1998 1,740

EW 963 608105006800 Marathon Oil Company 6/29/1998 1,758

EW 965 608105008003 Eni Petroleum Co Inc 1/26/2002 1,694

EW 966 608104010001 Mariner Energy Inc 5/12/2000 1,853

EW 991 608104009300 Walter Oil & Gas Corporation 7/06/1996 765

EW 1006 608105004102 Walter Oil & Gas Corporation 3/01/2002 1,884

EW 1006 608104012100 Walter Oil & Gas Corporation 6/23/2003 1,851

EW 1006 608104012200 Walter Oil & Gas Corporation 8/27/2003 1,854

GA A 192 427074010300 Walter Oil & Gas Corporation 5/22/2003 242

GB 108 608074020600 Kerr-McGee Oil & Gas Corporation 7/17/1999 619

GB 117 608074013500 Flextrend Development Company LLC 7/16/1996 922

GB 117 608074014901 Flextrend Development Company LLC 5/05/1997 924

GB 139 608074064501 W & T Offshore Inc 11/25/2002 550

GB 152 608074020800 Walter Oil & Gas Corporation 7/07/1999 619
133 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

GB 158 608074021702 Amerada Hess Corporation 1/28/2002 1,050

GB 161 608074015801 Newfield Exploration Company 9/20/1999 972

GB 161 608074017500 Newfield Exploration Company 11/17/1999 970

GB 179 608074063700 Walter Oil & Gas Corporation 10/12/1997 712

GB 184 608074065100 Kerr-McGee Oil & Gas Corporation 3/20/2003 698

GB 200 608074021100 Amerada Hess Corporation 11/29/2000 1,736

GB 201 608074023701 Amerada Hess Corporation 11/02/2002 1,736

GB 201 608074027002 Amerada Hess Corporation 9/05/2005 1,736

GB 205 608074024103 LLOG Exploration Offshore Inc 8/30/2002 1,330

GB 215 608074016001 Amerada Hess Corporation 12/15/2000 1,450

GB 215 608074020101 Amerada Hess Corporation 2/19/2001 1,457

GB 215 608074017202 Amerada Hess Corporation 12/30/2002 1,464

GB 216 608074081901 Amerada Hess Corporation 5/22/1999 1,456

GB 216 608074022600 Amerada Hess Corporation 6/20/2001 1,481

GB 224 608074061800 Kerr-McGee Oil & Gas Corporation 5/22/1991 742

GB 235 608074010600 W & T Offshore Inc 11/10/1994 785

GB 236 608074063300 Chevron USA Inc 9/08/1997 685

GB 341 608074025401 Shell Offshore Inc 6/14/2003 2,013

GB 341 608074019104 Shell Offshore Inc 7/30/2003 2,015

GB 409 608074016300 ATP Oil & Gas Corporation 5/12/2001 1,355

GB 409 608074063500 ATP Oil & Gas Corporation 5/16/2001 1,360

GB 472 608074020903 Shell Offshore Inc 10/21/2001 3,380

GB 472 608074024303 Shell Offshore Inc 4/24/2003 3,392

GB 516 608074022402 Shell Offshore Inc 11/21/2001 3,400

GB 559 608074019901 Shell Offshore Inc 8/03/2001 3,400

GB 559 608074022103 Shell Offshore Inc 9/02/2001 3,400

GB 559 608074023901 Shell Offshore Inc 3/18/2003 3,393

GB 602 608074019401 Shell Offshore Inc 8/16/1999 3,693

GB 602 608074014401 Shell Offshore Inc 12/28/1999 3,708

GB 602 608074019301 Shell Offshore Inc 2/27/2001 3,708

GB 667 608074065803 Kerr-McGee Oil & Gas Corporation 2/18/2004 3,105

GB 668 608074067500 Kerr-McGee Oil & Gas Corporation 1/03/2006 3,137

GC 20 608114021300 Shell Gulf of Mexico Inc 12/10/1999 880
134 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

GC 50 608114038500 LLOG Exploration Offshore Inc 5/05/2004 922

GC 50 608114043400 LLOG Exploration Offshore Inc 10/26/2005 690

GC 60 608114020101 Mobil Oil Exploration & Producing 6/22/1996 868

GC 110 608114020600 Shell Offshore Inc 1/23/1996 1,730

GC 112 608115024501 Shell Deepwater Development Inc 7/13/2000 1,968

GC 113 608115013100 Marubeni Oil & Gas (USA) Inc 7/17/1999 1,968

GC 113 608115012701 Marubeni Oil & Gas (USA) Inc 9/01/1999 2,045

GC 116 608115008600 Shell Offshore Inc 1/11/1996 2,046

GC 116 608115012200 Shell Offshore Inc 2/14/1998 2,046

GC 136 608114020000 Chevron USA Inc 11/21/1995 860

GC 136 608114029600 Chevron USA Inc 11/19/2002 990

GC 137 608114039202 LLOG Exploration Offshore Inc 3/31/2004 1,168

GC 155 608114031100 Shell Offshore Inc 6/23/2002 1,939

GC 157 608114037100 LLOG Exploration Offshore Inc 6/12/2002 1,890

GC 157 608114043801 LLOG Exploration Offshore Inc 11/11/2005 2,614

GC 200 608114021800 Shell Offshore Inc 11/10/1997 2,670

GC 200 608114021600 Shell Offshore Inc 12/07/1997 2,670

GC 200 608114020501 Shell Offshore Inc 6/29/1998 2,670

GC 200 608114021901 Shell Offshore Inc 2/27/1999 2,670

GC 200 608114028900 Shell Offshore Inc 1/25/2001 2,672

GC 237 608114024100 Chevron USA Inc 6/13/2001 2,025

GC 237 608114023101 Chevron USA Inc 7/09/2001 2,025

GC 237 608114024704 Chevron USA Inc 6/10/2003 1,982

GC 243 608114027606 Nexen Petroleum USA Inc 9/19/2002 3,065

GC 243 608114034000 Nexen Petroleum USA Inc 12/28/2002 3,048

GC 244 608114021701 Shell Offshore Inc 3/02/1998 2,670

GC 254 608115009001 Eni Petroleum Co Inc 8/16/2000 3234

GC 254 608115008001 Eni Petroleum Co Inc 11/04/2001 3226

GC 282 608114030804 BHP Billiton Petroleum (GOM) Inc 11/22/2002 2,386

GC 282 608114033701 BHP Billiton Petroleum (GOM) Inc 8/01/2003 2,370

GC 297 608115009400 Eni Petroleum Co Inc 9/11/2001 3,308

GC 473 608114027300 Eni Petroleum Co Inc 9/15/2001 3,840

GC 516 608114030101 Eni Petroleum Co Inc 10/02/2001 3,839
135 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

GC 768 608114041704 Kerr-McGee Oil & Gas Corporation 1/11/2006 5,272

GI 32 177174011700 BP America Production Company 3/09/1980 98

GI 101 177184010500 Walter Oil & Gas Corporation 9/29/2002 215

GI 109 177184009600 Walter Oil & Gas Corporation 10/16/2000 280

HI A 308 427114085500 Tarpon Offshore LP 8/16/2004 212

HI A 309 427114070100 SPN Resources LLC 1/24/1995 213

HI A 316 427114084301 El Paso Production Oil & Gas Co 11/23/2002 217

HI A 336 427114086100 Tarpon Offshore LP 12/31/2004 235

HI A 343 427114082501 Tarpon Offshore LP 2/26/2005 257

HI A 345 427114083000 Seneca Resources Corporation 7/26/2003 238

HI A 355 427114084100 Newfield Exploration Company 12/15/2002 285

HI A 378 427114075700 Kerr-McGee Oil & Gas Corporation 7/28/1996 360

HI A 531 427094106900 Hunt Oil Company 8/25/1999 194

HI A 531 427094109100 Hunt Oil Company 3/24/2001 194

HI A 544 427094113200 Energy Resource Technology Inc 9/06/2003 234

HI A 573 427094053700 Apache Corporation 9/17/1980 350

MC 28 608164018600 BP Exploration & Production Inc 4/21/1995 1,290

MC 28 608174051900 BP Exploration & Production Inc 6/30/1996 1,853

MC 28 608174051600 BP Exploration & Production Inc 8/16/1996 1,853

MC 28 608174052000 BP Exploration & Production Inc 4/24/1998 1,853

MC 28 608174051704 BP Exploration & Production Inc 6/26/2001 1,853

MC 66 608174100101 Mariner Energy Inc 9/03/2003 1,144

MC 68 608174088600 Walter Oil & Gas Corporation 6/03/2000 1,337

MC 72 608174051500 BP Exploration & Production Inc 4/27/1996 1,853

MC 72 608174051800 BP Exploration & Production Inc 2/14/1997 1,853

MC 84 608174096500 BP Exploration & Production Inc 2/05/2003 5,418

MC 85 608174090801 BP Exploration & Production Inc 5/13/2001 5,317

MC 85 608174090100 BP Exploration & Production Inc 6/15/2001 5,173

MC 161 608174106702 Walter Oil & Gas Corporation 8/23/2005 2,924

MC 167 608174088800 Exxon Mobil Corporation 10/28/2000 4,350

MC 211 608174088900 Exxon Mobil Corporation 11/22/2000 4,317

MC 211 608174099200 Exxon Mobil Corporation 8/28/2002 4,318

MC 217 608174091001 ATP Oil & Gas Corporation 8/22/2001 6,420
136 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

MC 217 608174090900 ATP Oil & Gas Corporation 1/07/2002 6,390

MC 278 608174091502 Walter Oil & Gas Corporation 5/21/2001 560

MC 292 608174050900 Chevron USA Inc 5/25/1999 3,405

MC 292 608174083201 Chevron USA Inc 8/25/1999 3,393

MC 292 608174083301 Chevron USA Inc 9/24/1999 3,393

MC 299 608174091202 Dominion Exploration & Production Co 5/13/2005 5,881

MC 305 608174091700 Total E&P USA Inc 5/01/2002 7,096

MC 305 608174083400 Total E&P USA Inc 7/12/2002 7,073

MC 305 608174098201 Total E&P USA Inc 8/15/2002 7,067

MC 305 608174087501 Total E&P USA Inc 9/11/2002 7,001

MC 321 608174089100 Walter Oil & Gas Corporation 9/15/2000 567

MC 322 608174093800 Walter Oil & Gas Corporation 7/08/2001 680

MC 348 608174084801 Marathon Oil Company 2/15/2002 7,209

MC 348 608174086801 Marathon Oil Company 5/31/2002 7,202

MC 354 608174044700 Exxon Mobil Corporation 7/05/1993 1,460

MC 355 608174044900 Exxon Mobil Corporation 5/29/1993 1,460

MC 355 608174044800 Exxon Mobil Corporation 9/11/1993 1,458

MC 355 608174084301 Exxon Mobil Corporation 7/02/1999 1,458

MC 357 608174053801 Newfield Exploration Company 2/25/1998 445

MC 383 608174094601 BP Exploration & Production Inc 8/11/2002 5,735

MC 383 608174094702 BP Exploration & Production Inc 8/26/2002 5,739

MC 400 608174096101 Apache Corporation 6/13/2005 1,139

MC 429 608174051300 BP Exploration & Production Inc 10/23/2002 6,240

MC 429 608174095402 BP Exploration & Production Inc 2/02/2003 6,101

MC 429 608174084404 BP Exploration & Production Inc 2/19/2003 6,134

MC 441 608174038400 Newfield Exploration Gulf Coast Inc 11/20/1992 1,531

MC 441 608174040100 Newfield Exploration Gulf Coast Inc 12/27/1992 1,531

MC 441 608174040002 Newfield Exploration Gulf Coast Inc 1/26/1993 1,531

MC 441 608174037601 Newfield Exploration Gulf Coast Inc 4/17/1993 1,438

MC 441 608174041500 Newfield Exploration Gulf Coast Inc 7/03/1993 1,438

MC 485 608174041600 Newfield Exploration Gulf Coast Inc 5/24/1993 1,438

MC 520 608174054601 BP Exploration & Production Inc 7/01/2002 6,738

MC 522 608174096900 BP Exploration & Production Inc 11/26/2002 6,932
137 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

MC 522 608174097000 BP Exploration & Production Inc 12/16/2002 6,934

MC 522 608174085802 BP Exploration & Production Inc 12/31/2002 6,940

MC 538 608174101301 Murphy Exploration & Production Co 2/16/2005 1,849

MC 608 608174098400 BP Exploration & Production Inc 7/22/2002 6,623

MC 661 608174083900 Pogo Producing Company 11/13/2001 854

MC 674 608174054404 Mariner Energy Inc 12/29/1999 2,710

MC 674 608174105502 Mariner Energy Inc 3/22/2005 2,799

MC 686 608174054100 Shell Offshore Inc 7/12/1997 5,292

MC 686 608174099600 Shell Offshore Inc 3/12/2003 5,318

MC 687 608174054000 Shell Offshore Inc 11/20/1998 5,292

MC 705 608174086001 Pogo Producing Company 12/24/2001 854

MC 730 608174054200 Shell Offshore Inc 11/04/1997 5,295

MC 755 608174057300 Anadarko E&P Company LP 12/11/2005 2,975

MC 763 608174047700 Shell Offshore Inc 8/08/1997 2,945

MC 764 608174058701 BP Exploration & Production Inc 4/06/2000 3,283

MC 765 608174100501 Shell Offshore Inc 7/18/2003 3,642

MC 765 608174098802 Shell Offshore Inc 12/29/2003 3,642

MC 766 608174096302 Shell Offshore Inc 9/11/2003 3,637

MC 771 608174102404 Dominion Exploration & Production Co 1/20/2005 5,413

MC 772 608174099100 Dominion Exploration & Production Co 3/16/2005 5,380

MC 806 608174049501 Shell Offshore Inc 1/03/2005 2,945

MC 807 608174038800 Shell Offshore Inc 3/25/1996 2,956

MC 822 608174038800 BP Exploration & Production Inc 11/10/2004 6,034

MC 837 608174092401 Walter Oil & Gas Corporation 6/22/2001 1,524

MC 899 608174058002 Shell Offshore Inc 7/24/2001 4,393

MC 899 608174091600 Shell Offshore Inc 8/13/2001 4,393

MC 899 608174087807 Shell Offshore Inc 10/31/2001 4,389

MC 934 608174083501 Shell Offshore Inc 11/13/1999 3,875

MC 934 608174083601 Shell Offshore Inc 3/10/2000 3,875

MC 934 608174083700 Shell Offshore Inc 9/01/2001 3,875

MI 685 427034054400 EOG Resources Inc 7/07/2004 90

MP 149 177254058901 Walter Oil & Gas Corporation 9/06/1994 220

MP 150 177254069600 Walter Oil & Gas Corporation 12/3/2000 245
138 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

MP 260 177244081400 Devon SFS Operating Inc 4/26/1999 315

MP 263 177244089600 Magnum Hunter Production Inc 3/31/2003 280

MP 280 177244091200 Dominion Exploration & Production Co 2/09/2005 307

MP 286 177244090400 Walter Oil & Gas Corporation 11/17/2003 292

MU 806 427024024500 Apache Corporation 11/30/1995 164

PN 996 427134009900 F-W Oil Exploration LLC 11/14/2003 159

PN A 9 427134050200 Newfield Exploration Company 11/05/2003 201

SM 195 177084093200 Tarpon Offshore LP 2/25/2005 300

SP 32 177212050500 Devon Louisiana Corporation 6/12/2002 115

SS 321 177124057000 ATP Oil & Gas Corporation 5/29/1997 323

ST 177 177154007800 Chevron USA Inc 11/06/1976 144

ST 231 177164019900 W & T Offshore Inc 6/25/1998 238

ST 239 177164031300 Walter Oil & Gas Corporation 9/25/2003 162

ST 248 177164029700 PRS Offshore LP 6/04/2002 178

ST 260 177164029501 ConocoPhillips Company 2/17/2004 288

VK 738 608164036601 Newfield Exploration Company 9/24/2000 809

VK 783 608164013401 Shell Offshore Inc 4/08/1991 1,494

VK 783 608164021701 Shell Offshore Inc 7/18/1996 1,142

VK 783 608164022301 Shell Offshore Inc 12/20/1996 1,450

VK 783 608164022400 Shell Offshore Inc 12/20/1996 1,451

VK 783 608164022501 Shell Offshore Inc 1/22/1997 1,451

VK 784 608164023200 Shell Offshore Inc 6/30/1996 1,750

VK 825 608164033201 Kerr-McGee Oil & Gas Corporation 10/16/1998 1,722

VK 825 608164034400 Kerr-McGee Oil & Gas Corporation 8/29/1999 1,711

VK 862 608164021600 Walter Oil & Gas Corporation 11/15/1995 1,067

VK 869 608164042300 Kerr-McGee Oil & Gas Corporation 1/01/2004 2,033

VK 869 608164043000 Kerr-McGee Oil & Gas Corporation 12/29/2004 2,050

VK 873 608164033601 Shell Offshore Inc 12/29/2001 3,463

VK 914 608164028403 BP Exploration & Production Inc 3/15/2001 3,535

VK 915 608164038300 BP Exploration & Production Inc 5/18/2001 3,460

VK 915 608164040200 BP Exploration & Production Inc 4/17/2002 3,460

VK 917 608164040000 Noble Energy Inc 10/21/2004 4,370

VK 944 608164040602 Walter Oil & Gas Corporation 5/02/2002 730
139 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

VK 961 608164043100 Noble Energy Inc 8/24/2004 4,677

VK 962 608164039901 Noble Energy Inc 8/24/2004 4,677

VK 986 608164022800 Walter Oil & Gas Corporation 12/23/1995 893

VK 986 608164040800 Walter Oil & Gas Corporation 5/26/2002 895

VR 51 177054118800 Bois D’Arc Offshore Ltd 5/31/2004 17

VR 116 177054107201 W & T Offshore Inc 4/19/1998 55

VR 272 177054034600 LLOG Exploration Offshore Inc 7/19/2004 175

VR 332 177064091100 Noble Energy Inc 10/19/2002 223

WC 22 177004118800 Newfield Exploration Company 3/22/2004 28

WC 625 177024132702 LLOG Exploration Offshore Inc 10/29/2004 338

WC 635 177024127500 ATP Oil & Gas Corporation 1/08/2001 360

WC 638 177024116900 Newfield Exploration Company 11/06/1998 373

WD 45 177190038402 Nexen Petroleum USA Inc 12/08/1981 50

WD 106 177194070300 Walter Oil & Gas Corporation 6/14/2001 254

WD 107 177194058000 Walter Oil & Gas Corporation 1/02/1996 250

WD 107 177194056400 Walter Oil & Gas Corporation 1/02/1996 222

WD 112 177204014901 Tarpon Offshore LP 1/12/2005 277
141 

Appendix F. Annual GOM Oil and Gas Production. 

Year 

Shallowwater Oil 

(MMB) 

Deepwater 

Oil (MMB) 

Total GOM 

Oil (MMB) 

Shallowwater Gas 

(BCF) 

Deepwater 

Gas (BCF) 

Total GOM 

Gas (BCF) 

1947 0 0 0 0 0 0

1948 0 0 0 0 0 0

1949 0 0 0 0 0 0

1950 0 0 0 0 0 0

1951 0 0 0 2 0 2

1952 1 0 1 19 0 19

1953 1 0 1 25 0 25

1954 2 0 2 60 0 60

1955 4 0 4 87 0 87

1956 7 0 7 91 0 91

1957 12 0 12 93 0 93

1958 20 0 20 144 0 144

1959 30 0 30 224 0 224

1960 41 0 41 281 0 281

1961 56 0 56 335 0 335

1962 77 0 77 451 0 451

1963 96 0 96 561 0 561

1964 111 0 111 645 0 645

1965 136 0 136 743 0 743

1966 175 0 175 992 0 992

1967 210 0 210 1,285 0 1,285

1968 254 0 254 1,600 0 1,600

1969 292 0 292 1,950 0 1,950

1970 329 0 329 2,402 0 2,402

1971 376 0 376 2,729 0 2,729

1972 373 0 373 3,004 0 3,004

1973 366 0 366 3,312 0 3,312

1974 338 0 338 3,418 0 3,418

1975 310 0 310 3,427 0 3,427

1976 301 0 301 3,556 0 3,556

1977 284 0 284 3,767 0 3,767

1978 276 0 276 4,244 0 4,244

1979 263 1 263 4,668 0 4,669

1980 260 5 265 4,762 4 4,766

1981 260 4 263 4,886 3 4,889

1982 273 13 286 4,651 16 4,666

1983 294 26 321 4,034 41 4,076
142 

Year 

Shallowwater Oil 

(MMB) 

Deepwater 

Oil (MMB) 

Total GOM 

Oil (MMB) 

Shallowwater Gas 

(BCF) 

Deepwater 

Gas (BCF) 

Total GOM 

Gas (BCF) 

1984 330 25 355 4,527 39 4,566

1985 330 21 351 4,047 34 4,081

1986 337 19 356 4,028 37 4,065

1987 311 17 328 4,501 44 4,545

1988 289 13 302 4,554 38 4,592

1989 271 10 281 4,618 32 4,650

1990 263 12 275 4,886 31 4,917

1991 272 23 295 4,648 58 4,707

1992 268 37 305 4,569 87 4,656

1993 272 37 309 4,556 120 4,675

1994 273 42 315 4,685 159 4,845

1995 290 55 345 4,614 181 4,795

1996 297 72 369 4,816 278 5,094

1997 303 108 412 4,776 382 5,158

1998 285 159 444 4,488 560 5,049

1999 270 225 495 4,217 846 5,062

2000 252 271 523 3,967 999 4,966

2001 243 315 558 3,882 1,177 5,060

2002 219 348 567 3,239 1,284 4,523

2003 211 350 561 3,005 1,425 4,430

2004 187 348 535 2,606 1,396 4,002
143 

Appendix G. GOM Platforms Destroyed by Hurricanes (2004-2005) 

Platforms Destroyed by Ivan (September 2004) 

Area/Block Number of platforms Facility Water Depth (ft) 

MC 20 1 A 479 

MP 98 1 A 79 

MP 293 2 “SONAT”, A 232, 247 

MP 305 1 C 244 

MP 306 1 E 255 

VK 294 1 A 119 

Platforms Destroyed by Katrina (August 2005) 

Area/Block Number of platforms Facility Water Depth (ft) 

GI 32 1 J 106 

GI 40 2 B, F 83, 86 

GI 41 1 A 91 

GI 47 1 C 88 

GI 48 1 D 86 

MP 138 1 A 158 

MP 270 1 A 205 

MP 298 1 B-Valve 222 

MP 306 1 D 255 

MP 312 1 JA 248 

PL 20 1 39 30 

SP 62 2 A, B 340, 322 

ST 21 10 75, 71, 67, 1, 22, 

27, 66, 25, E, 31 

47, 48, 46, 37, 36, 

40, 45, 40, 40, 36 

ST 135 1 M 116 

ST 151 3 O, I, G 137, 128, 137 

ST 161 2 B, A 120, 117 

ST 176 1 A 140 

WD 69 2 C, K 121, 134 

WD 70 1 H 141 

WD 94 1 G 153 

WD 103 2 B, A 228, 223 

WD 104 1 C 228 

WD 117 5 D, E, C, QRT, 

F 

195, 208, 214, 214, 

200 

WD 133 1 B 285 

WD 137 1 A 310 

WD 95 1 #5 Well 150 
144 

Platforms Destroyed by Rita (September 2005) 

Area/Block Number of platforms Facility Water Depth (ft) 

EC 71 1 B 53 

EC 151 1 C 80 

EC 160 2 C, A-AUX 84, 85 

EC 161 1 A 85 

EC 195 1 A 103 

EC 222 2 D, A-PROD 123, 110 

EC 254 1 B 164 

EC 272 2 A-AUX1, A 182, 182 

EC 286 1 B 186 

EC 322 1 A 230 

EI 276 2 D, B-PROD 176, 172 

EI 294 1 A 204 

EI 313 2 B, C 240, 230 

EI 314 2 F, J 230, 230 

EI 330 1 S 254 

EI 333 1 A 231 

EI 338 1 A 253 

GC 237 1 (final loc. EI270) A-Typhoon TLP 2107 

HI A467 1 D 187 

SM 11 3 K, B, J 68, 68, 68 

SM 49 1 B 98 

SM 66 2 A, E 128, 134 

SM 76 1 B 140 

SM 90 1 A 163 

SM 108 1 D 183 

SM 128 1 A-PRD 228 

SS 69 1 16 28 

SS 169 1 A 54 

SS 177 1 C 92 

SS 181 1 K 67 

SS 193 1 B 86 

SS 218 1 D 112 

SS 219 1 C 113 

SS 253 1 A-AUX 165 

SS 269 1 A 170 

ST 51 1 CH 62 

ST 146 1 A 170 

ST 161 1 D 120 

VR 131 2 5, CF 56, 57 

VR 201 1 A 83 

VR 217 1 A 121 

VR 245 2 B, C-DRILL 126, 131 

VR 255 2 B, A 152, 158 

VR 273 1 A 185 

VR 340 1 JA 227 

WC 45 1 5 28 

WC 56 1 CAIS #15 34 

WC 110 4 3, 9, 10, 1 40, 41, 40, 40 

WC 172 1 E 47 

WC 176 1 2 49 

WC 229 1 A 65 

WC 313 1 1 49 

 
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 

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 territories under U.S. administration. 

The Minerals Management Service Mission 

As a bureau of the Department of the Interior, the Minerals Management Service's (MMS) 

primary responsibilities are to manage the mineral resources located on the Nation's Outer 

Continental Shelf (OCS), collect revenue from the Federal OCS and onshore Federal and Indian 

lands, and distribute those revenues. 

Moreover, in working to meet its responsibilities, the Offshore Minerals Management Program 

administers the OCS competitive leasing program and oversees the safe and environmentally 

sound exploration and production of our Nation's offshore natural gas, oil and other mineral 

resources. The MMS Minerals Revenue Management meets its responsibilities by ensuring the 

efficient, timely and accurate collection and disbursement of revenue from mineral leasing and 

production due to Indian tribes and allottees, States and the U.S. Treasury. 

The MMS strives to fulfill its responsibilities through the general guiding principles of: (1) being 

responsive to the public's concerns and interests by maintaining a dialogue with all potentially 

affected parties and (2) carrying out its programs with an emphasis on working to enhance the 

quality of life for all Americans by lending MMS assistance and expertise to economic 

development and environmental protection.