ERRATA

Figure 1

P. 4, The colored areas marked as “Royalty Relief Zones” are water-depth zones that correspond 

with Deep Water Royalty Relief Act (DWRRA) water depths. Not all leases within a colored 

area are eligible for royalty relief due to the different vintage leases included in the area. In 

addition, please note that the colored areas extend past the official royalty relief area 

authorized by the DWRRA and that leases east of 87 degrees, 30 minutes West longitude in 

the Eastern Planning Area are not eligible for royalty relief.

P. 112, last line, “51%” should read “48%.”

Appendix B

P. 125, line 2, clarification: the Pardner project may appear to be the first deepwater discovery 

because it was combined with a field discovered in water depths less than 1,000 ft. The 

shallow-water portion of the WD152 field was indeed discovered in 1968, but the deepwater 

portion of the field (the Pardner project) was not drilled until 2002.

Appendix H

P. 150, line 12, column 5: “2.7” should read “12.7.”

P. 150, line 13, column 5: “3.4” should read “13.4.”

P. 150, line 14, column 5: “2.8” should read “12.8.”
ON COVER – The cover features four images of the deepwater frontier (top to bottom). Transocean’s deepwater 

drillship Discoverer Deep Seas, which set a world record drilling in 10,011 ft of water at ChevronTexaco’s Toledo 

prospect (photo courtesy of Transocean). A sperm whale surfaces near BP’s Horn Mountain spar and Heerema’s 

construction vessel Balder (photo courtesy of Christopher Richter). The Na Kika semisubmersible, installed by 

Shell and operated by BP, which will gather production from six subsea projects by the end of 2004 (photo courtesy 

of Shell International Exploration and Production Inc. and BP). An artist’s rendering of subsea equipment installed 

at a deepwater location (image courtesy of Shell International Exploration and Production Inc.).
OCS Report 

MMS 2004-021 

Deepwater Gulf of Mexico 2004: 

America’s Expanding Frontier

Authors 

G. Ed Richardson 

Leanne S. French 

Richie D. Baud 

Robert H. Peterson 

Carla D. Roark 

Tara M. Montgomery 

Eric G. Kazanis 

G. Michael Conner 

Michael P. Gravois 

Published by 

U.S. Department of the Interior 

Minerals Management Service New Orleans 

Gulf of Mexico OCS Region May 2004 

Table of Contents Page

iii 

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

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

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

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

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

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

Exploration Activity ...............................................................................................................................6

Leasing Activity ...................................................................................................................................13

Environmental Activity ........................................................................................................................21

Ocean Current Monitoring ...................................................................................................................23

Challenges and Rewards ......................................................................................................................26

LEASING ...................................................................................................................................................37

Bidding and Leasing Trends.................................................................................................................37

Lease Ownership ..................................................................................................................................42

Future Lease Activity ...........................................................................................................................42

DRILLING AND DEVELOPMENT..........................................................................................................47

Drilling Activity ...................................................................................................................................47

Development Systems ..........................................................................................................................58

Subsea Trends.......................................................................................................................................70

New Pipelines.......................................................................................................................................70

RESERVES AND PRODUCTION ............................................................................................................75

Discoveries ...........................................................................................................................................75

Reserve Potential..................................................................................................................................82

Production Trends ................................................................................................................................84

Companies and Production...................................................................................................................90

Production Rates...................................................................................................................................90

SUMMARY AND CONCLUSIONS .......................................................................................................101

Development Cycle ............................................................................................................................101

Drilling the Lease Inventory...............................................................................................................107

Expanding Frontier.............................................................................................................................111

CONTRIBUTING PERSONNEL.............................................................................................................115

REFERENCES .........................................................................................................................................117
Table of Contents — continued Page

iv 

APPENDICES ..........................................................................................................................................119

Appendix A. Announced Deepwater Discoveries (Sorted by Project Name). .................................119

Appendix B. Announced Deepwater Discoveries (Sorted by Discovery Date). ..............................125

Appendix C. Chronological Listing of GOM Lease Sales by Sale Location and Sale Date. ...........131

Appendix D. Deepwater Studies Program........................................................................................133

Appendix E. Companies Defined as Majors in this Report. ............................................................135

Appendix F. Number of Deepwater Production Facilities Installed Each Year 

(including Plans through 2006)...................................................................................139

Appendix G. Subsea Completions....................................................................................................140 

Appendix H. Average Annual GOM Oil and Gas Production. ........................................................149 
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 shaded 

Deep Water Royalty Relief Act zones.................................................................................... 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 2003........................ 9

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

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

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

Figure 7. Location of known gas hydrates in the Gulf of Mexico. ...................................................... 14

Figure 8. Gas hydrates on the seafloor in Green Canyon Block 185 

(photo courtesy of GERG/Texas A&M University)............................................................. 15

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

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

Figure 11. Total active leases by water depth. ....................................................................................... 19

Figure 12. Environmental and deepwater administrative features. ........................................................ 20

Figure 13. Grid EA status....................................................................................................................... 22

Figure 14. ROV surveys including known chemosynthetic communities. ............................................ 24

Figure 15. Loop and eddy currents in the Gulf of Mexico 

(image courtesy of Horizon Marine, Inc.). ........................................................................... 25

Figure 16. Deepwater discoveries in the Gulf of Mexico. ..................................................................... 27

Figure 17. Ownership of deepwater discoveries (includes industry-announced discoveries)................ 29

Figure 18. Estimated volumes of 80 proved deepwater fields. .............................................................. 30

Figure 19. Onshore service bases for existing deepwater structures...................................................... 31

Figure 20. Onshore service bases for pending deepwater plans............................................................. 32

Figure 21. Current, potential, and future hub facilities in the Gulf of Mexico. ..................................... 33

Figure 22. Oil and gas pipelines with diameters greater than or equal to 20 inches. ............................. 35

Figure 23. Deepwater oil and gas pipelines in the Gulf of Mexico........................................................ 36

Figure 24. Number of leases issued each year, subdivided by DWRRA water-depth categories.......... 38

Figure 25a. Number of leases bid on for each deepwater interval........................................................... 39

Figure 25b. Total bid amounts in deepwater intervals. ............................................................................ 39

Figure 25c. Average bid amount per block in deepwater intervals.......................................................... 39

Figure 26. Rejected shallow- and deepwater Gulf of Mexico bids. ....................................................... 40

Figure 27. Ownership of deepwater leases............................................................................................. 43

Figure 28. Anticipated lease expirations in the Gulf of Mexico. ........................................................... 45

Figure 29. The Deepwater Horizon, a dynamically positioned, semisubmersible drilling unit 

(photo courtesy of Transocean). ........................................................................................... 48
Figures — continued Page

vi 

Figure 30. The Discoverer Deep Seas, a Class 1A1, double-hulled, dynamically positioned 

drillship (photo courtesy of Transocean). ............................................................................. 49

Figure 31. Average number of rigs operating in the deepwater GOM. (White bars are estimates.)...... 50

Figure 32. 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. .................................................................... 50

Figure 33. All deepwater wells drilled in the Gulf of Mexico, subdivided by water depth. .................. 51

Figure 34. All deepwater exploratory wells drilled in the Gulf of Mexico by water depth. .................. 52

Figure 35. Deepwater development wells drilled in the Gulf of Mexico, divided by water depth. ....... 53

Figure 36. Deepwater exploratory wells drilled in the Gulf of Mexico. ................................................ 54

Figure 37. Deepwater development wells drilled in the Gulf of Mexico............................................... 56

Figure 38. Deepwater EP's, DOCD's, and DWOP's received in the Gulf of Mexico since 1992. ......... 59

Figure 39. Maximum wellbore true vertical depth (TVD) drilled in the total 

Gulf of Mexico each year. .................................................................................................... 60

Figure 40. Maximum water depth drilled each year. ............................................................................. 61

Figure 41. Deepwater development systems.......................................................................................... 62

Figure 42. Three different development systems (left to right): a SeaStar TLP installed at 

ChevronTexaco’s Typhoon field, a spar installed at ChevronTexaco’s Genesis 

Field, and a semisubmersible at Shell/BP’s Na Kika Field (images courtesy of 

ChevronTexaco, Shell International Exploration and Production Inc., and BP). ................. 66

Figure 43. Progression of spar deepwater development systems 

(image courtesy of Technip-Coflexip).................................................................................. 68

Figure 44. GOM deepwater production facilities installed each year 

(including plans through 2006). Inset shows production systems 

for currently producing fields (including subsea systems). .................................................. 69

Figure 45. Crosby Project (MC 899) subsea equipment layout 

(image courtesy of Shell International Exploration and Production Inc.). ........................... 71

Figure 46. Number of shallow- and deepwater subsea completions each year...................................... 72

Figure 47. Maximum water depth of subsea completions each year. .................................................... 72

Figure 48. Water depth of subsea completions. ..................................................................................... 73

Figure 49. Length of subsea tiebacks..................................................................................................... 73

Figure 50a. Approved deepwater oil and gas pipelines less than or equal to 12 inches in diameter. ...... 74

Figure 50b. Approved deepwater oil and gas pipelines greater than 12 inches in diameter. ................... 74

Figure 51. Proved reserve additions....................................................................................................... 76

Figure 52. Proved and unproved reserve additions. ............................................................................... 77

Figure 53. Average field size using proved and unproved reserves....................................................... 78

Figure 54. Number of deepwater field discoveries and resulting number of producing fields. ............. 79

Figure 55. Number of deepwater field discoveries and new hydrocarbons found 

(MMS reserves, MMS resources, and industry-announced discoveries).............................. 80
Figures — continued Page

vii 

Figure 56. BOE added (reserves, known resources, and industry-announced discoveries)................... 81

Figure 57. Modified creaming curve for shallow- and deepwater areas of the GOM 

(includes reserves, resources, and industry-announced discoveries).................................... 83

Figure 58. Reserves and future discovery volumes in the deepwater GOM. ......................................... 83

Figure 59. Relative volume of production from each GOM lease. Bar heights are 

proportional to total lease production (barrels of oil equivalent) during that interval.......... 85

Figure 60. Estimated U.S. oil and gas production in 2002..................................................................... 87

Figure 61a. Comparison of average annual shallow- and deepwater oil production. .............................. 88

Figure 61b. Comparison of average annual shallow- and deepwater gas production. ............................. 88

Figure 62a. Contribution of DWRRA oil production to total oil production 

in water depths greater than 200 m (656 ft).......................................................................... 89

Figure 62b. Contribution of DWRRA gas production to total gas production 

in water depths greater than 200 m (656 ft).......................................................................... 89

Figure 63a. Contributions from subsea completions toward total deepwater oil production................... 91

Figure 63b. Contributions from subsea completions toward total deepwater gas production. ................ 91

Figure 64a. Comparison of major and nonmajor companies in terms of deepwater oil production........ 92

Figure 64b. Comparison of major and nonmajor companies in terms of deepwater gas production....... 92

Figure 65a. Comparison of major and nonmajor companies in terms of 

shallow-water oil production. ............................................................................................... 93

Figure 65b. Comparison of major and nonmajor companies in terms of 

shallow-water gas production. .............................................................................................. 93

Figure 66a. Contributions from each major oil company toward total deepwater oil production. .......... 94

Figure 66b. Contributions from each major oil company toward total deepwater gas production. ......... 94

Figure 67a. Maximum production rates for a single well within each water-depth category 

for deepwater oil production................................................................................................. 95

Figure 67b. Maximum production rates for a single well within each water-depth category 

for deepwater gas production................................................................................................ 95

Figure 68a. Average production rates for shallow-water and deepwater oil well completions. .............. 97

Figure 68b. Average production rates for shallow-water and deepwater gas well completions.............. 97

Figure 69a. Deepwater oil production profiles 

(oil wells coming onstream between 1992 and 2002). ......................................................... 98

Figure 69b. Deepwater gas production profiles 

(gas wells coming onstream between 1992 and 2002). ........................................................ 98

Figure 70a. Maximum historical oil production rates for Gulf of Mexico wells..................................... 99

Figure 70b. Maximum historical gas production rates for Gulf of Mexico wells.................................. 100

Figure 71. Deepwater projects that began production in 2003 and those expected 

to begin production by yearend 2007. ................................................................................ 102

Figure 72. Deepwater lease activity and oil/natural gas prices (prices from U.S. Energy 

Information Administration: oil through September 2003 and natural gas 

through July 2003).............................................................................................................. 103
Figures — continued Page

viii 

Figure 73a. Lag from leasing to first well for producing deepwater fields............................................ 105

Figure 73b. Lag from leasing to qualifying for producing deepwater fields.......................................... 105

Figure 73c. Lag from leasing to first production for producing deepwater fields. ................................ 105

Figure 74. Year in the lease term in which BOE was discovered and percent of leases 

were tested, for deepwater leases, 1974-1994. ................................................................... 106

Figure 75. Activity on deepwater leases. ............................................................................................. 108

Figure 76a. Leases drilled and barrels found. ........................................................................................ 109

Figure 76b. Exploration effort and reward: number of leases drilled in a year 

and BOE discovered per lease. ........................................................................................... 109

Figure 77a. Relationship between number of leases issued and number of leases 

 drilled, 1974-1993.............................................................................................................. 110

Figure 77b. Relationship between number of leases issued and number of resulting 

producing leases, 1974-1993. ............................................................................................. 110

Figure 77c. Relationship between number of leases drilled and number of resulting 

producing leases, 1974-1993. ............................................................................................. 110

Figure 78. The challenge of deepwater lease evaluation...................................................................... 111

Figure 79. Comparison of 2000, 2002, and 2004 deepwater GOM reports: successive 

increases in deepwater BOE. .............................................................................................. 112
Tables Page

ix 

Table 1 List of Deepwater Discoveries in Water Depths Greater than 7,000 ft (2,134 m)............... 12

Table 2 Completed Grid PEA’s Within the Central and Western Planning Areas 

of the Gulf of Mexico ........................................................................................................... 21

Table 3 LNG Projects Proposed in the Gulf of Mexico.................................................................... 34

Table 4 Development Systems of Productive Deepwater GOM Projects......................................... 63

Table 5 Top 20 Producing Blocks for the Years 2001—2002.......................................................... 84

xi 

PREFACE 

The Gulf of Mexico is now in its ninth year of sustained expansion of the deepwater frontier. Deepwater 

oil and gas exploration and development in the Gulf of Mexico OCS has succeeded probably beyond the 

most optimistic dreams of most of us and shows no sign of diminishment. This is the fourth report issued 

by MMS chronicling the beginning and unfolding of this frontier. 

Since those first steps taken by industry in 1995-1996, we have entered into a sustained, robust expansion 

of activity that promises to continue for many years to come. As 2004 begins, we have 90 hydrocarbon 

production projects on line. Production from the deepwater frontier grew to an estimated 959 thousand 

barrels of oil per day and 3.6 billion cubic feet of natural gas per day by the end of 2002. This was a rise 

of 535 percent and 620 percent for oil and gas, respectively, since 1995.

About 750 exploration wells have been drilled in the deepwater Gulf since 1995. At least 100 deepwater 

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

11 industry-announced discoveries in water depths greater than 7,000 ft (2,134 m), and these ultra-deep 

discoveries have the promise of opening up entirely new geologic frontiers. 

Of critical note, the new technology that has been developed and deployed to produce the Gulf of Mexico 

deepwater resources is the marvel of the world. Never-before-heard-of production from spars has now 

accelerated so that eight spars were in production by the end of 2003 with three more spars scheduled to 

begin production in 2004. These spars range from classic spars and truss spars to the first-ever cell spar, 

scheduled by Kerr McGee for installation in 2004. Similarly, a few years ago, there were no mini-tension 

leg platforms and now the SeaStar and the MOSES have arrived. Subsea production has expanded from a 

water depth of 1,462 ft (446 m) with Placid Oil Company’s Green Canyon Block 29 project in 1988 to 

5,318 ft (1,621 m) with Shell's Mensa in 1997, and to 7,216 ft (2,199 m) with Marathon’s Camden Hills 

in 2002. Shell and BP’s Coulomb/Na Kika project, scheduled this year, will establish subsea production 

in 7,591 ft (2,314 m) of water. 

The role played by the MMS in this major energy expansion has been critical — from ensuring the receipt 

of fair market value for the sale of the leases to the evaluation and approval of new technology, and to 

facing new challenges in drilling and new environmental questions. The MMS’s development of new 

environmental review procedures to ensure timely but thorough review and protection of environmental 

values has been innovative and critical to keep project timelines minimized. 

Chris C. Oynes 

Regional Director 

Minerals Management Service 

1 

INTRODUCTION 

The deepwater Gulf of Mexico (GOM) is an important oil and gas province and an integral part of the 

Nation’s oil and gas supply. 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 continues to 

increase and is rapidly approaching the all-time shallow-water GOM record set in 1971. In addition, 

deepwater drilling reached record levels in 2001. The average sizes of deepwater GOM field discoveries 

are several times larger than the average shallow-water field discoveries. In fact, since the last version of 

this report (Baud et al., 2002) some of the largest hydrocarbon accumulations ever discovered in the 

GOM were found in the deepwater area. The 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 and geologic plays, 

• environmental issues, 

• technology concerns, and 

• the existing deepwater infrastructure. 

The Leasing section discusses 

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

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

and 

• future deepwater lease activity. 

The Drilling and Development section discusses 

• deepwater rig activity, 

• historical drilling statistics, 

• the transition to deeper wells and deeper water, 

• the complexity of deepwater development systems, and 

• the progress of deepwater infrastructure development. 

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; 

• potential for numerous, large future deepwater field discoveries; 

• historical trends in deepwater production; 

• deepwater production from various companies; and 

• high deepwater production rates. 
2 

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, drilling, and initial production; 

• difficulties evaluating deepwater leases before their terms expire; and 

• significant changes since the 2002 report. 
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 Deep Water 

Royalty Relief (DWRR) zones (200, 400, 800, and 1,600 m) for reference. 

There are a variety of criteria that 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-to-be 

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 have not 

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, 2000 report (Crawford et al., 2003). 

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. Appendices A and B provide locations, operators, and additional 

information regarding 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. 

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 2002 

(the most recent, complete data available at the time of this publication). 
4

Eastern Planning Are

Eastern Planning Are

Florida

Mississippi Alabama

Louisiana

Texas

De Soto Canyon

Western Planning Area Central Planning Area Central Planning Area

G

7500 ft

1000 ft 1500 ft

5000 ft

Mississippi Canyon

Atwater Valley

Lund

Lund South Florida Plain

Henderson

Green Canyon Lloyd Ridge

Walker Ridge

Sigsbee Amery Terrace Escarpment

Keathley Canyon

East Breaks Garden Banks

Alaminos Canyon

G

Florida

Mississippi Alabama

Louisiana

Texas

Western Planning Area

200 - 399400 - 799800 - 1,599> 1,600

Royalty Relief Zones (meters) 50 

50 

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

report are shown in addition to shaded Deep Water Royalty Relief Act zones. 
5 

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, indeed, many of the anticipated fields have 

begun production since the 1997 report. The previous version of this report (Baud et al., 

2002)highlighted dramatic advancements from 1997 through 2001. Significant advances have continued 

and are described in this report. 

At the end of 2003, there were 86 producing projects in the deepwater GOM, up 51 percent in the two 

years since Baud et al. (2002). Deepwater production rates have risen by well over 100,000 barrels of oil 

per day (BOPD) and 400 million cubic ft of gas per day (MMCFPD), respectively, each year since 1997. 

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 12 years, 1992-2003. 

Over the last 12 years, there has been an overall expansion in all phases of deepwater activity. There are 

approximately 7,800 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 29 rigs drilling in deepwater in 2003, 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. 

Although deepwater production and the number of discoveries have increased substantially, some 

measures of deepwater activity have declined since the last report. There have been decreases in the 

average bid amount per block, average number of rigs operating, the number of wells drilled, and the 

number of deepwater plans submitted. 

All phases of exploration and development moved steadily into deeper waters over the past 12 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. Major oil companies continue to dominate deepwater oil and gas 

production. Production from major oil companies has continued to increase steadily, but production from 

nonmajor companies has remained flat. 

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

deepwater GOM activities. This legislation provides economic incentives for operators to develop fields 

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

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

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

400-800 m (1,312-2,624 ft) of water, and 87.5 MMBOE for a field in greater than 800 m (2,624 ft) of 

water.1

 

1

 Whether leases issued under the DWRRA (November 28, 1995 through November 28, 2000) are entitled to 

incentives on a field or a lease basis is currently under litigation. 
6 

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). Royalty relief volumes range from 5 MMBOE in water depths of 

400-799 m (1,312-2,621 ft) to 12 MMBOE of relief in depths greater than 1,600 m (5,249 ft). Royalty 

relief is granted to individual leases, not fields1

 as in the DWRRA. Post-DWRRA provisions are subject 

to change for each lease sale. 

SEISMIC ACTIVITY

A combination of factors including the DWRRA, several 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-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.) Three-dimensional 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 12 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 speculative PrSDM coverage. This figure was 

assembled from publicly available sources and 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). The high cost of drilling deepwater wells and challenges associated with reentry of 

deepwater wells may promote the use of 4-D technology in the deepwater GOM. 

EXPLORATION ACTIVITY

Modern seismic data often generate new ideas leading to surges in leasing and drilling activities. 

Exploration drilling in the deepwater GOM in 2002 and 2003 has found over 2 billion BOE. Traditional 

deepwater mini-basin plays are still providing many exploration opportunities (consider the Thunder 

Horse and North Thunder Horse discoveries in southern Mississippi Canyon), but recent discoveries in 

new deepwater plays continue to expand the exploration potential of the deepwater GOM. Figure 5 

illustrates the fact that 99 percent of total GOM production is from Neogene-age reservoirs (Pleistocene, 

Pliocene, and Miocene); however, several recently announced deepwater discoveries encountered large 

potential reservoirs in sands of Paleogene age (Oligocene, Eocene, and Paleocene). This older portion of 

the geologic section has been very lightly tested in the GOM and the discovery of reservoirs of this 

geologic age may open wide areas of the GOM to further drilling. Figure 6 illustrates two frontier 
7 

Texas

Florida

Alabama

Louisiana Mississippi

Texas

Florida

Alabama

Louisiana Mississippi

Texas

Florida

Alabama

Louisiana Mississippi

1994 - 1995

1996 - 1997

50 0 50 mi

50 0 50 km

1992 - 1993

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

Texas

Florida

Alabama

Louisiana Mississippi

Texas

Florida

Alabama

Louisiana Mississippi

Texas

Florida

Alabama

1998 - 1999

Louisiana Mississippi

2000 - 2001

2002 - 2003

50 0 50 mi

50 0 50 km

Figure 2. Progressive deepwater 3-D seismic permit coverage (continued). 
9

Texas

Alabama

Louisiana

Mississippi

50 0 50 km

50 0 50 

1992 - 2003

Figure 3. Deepwater Gulf of Mexico 3-D seismic permit coverage from 1992 to 2003. 
10

Texas

Louisiana

Mississippi

Alabama

50 0 50 

50 0 50 km

Figure 4. Pre-stack depth migration coverage from various industry sources. 
11 

Quaternary 

0 mya 

1.8 mya 

Pleistocene 

24 mya 

Neogene

Pliocene 

Miocene 

99% 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. 

Tertiary 

65 mya 

Paleogene 

Oligocene 

Eocene 

Paleocene 

• Newly announced discoveries in the 

deepwater open a large play area for 

exploration. 

Cretaceous 

144 mya 

Jurassic 

1% GOM 

proved 

reserves 

• Mesozoic potential extends into the Eastern 

GOM Sale areas. 

mya=million years ago 

Figure 5. Stratigraphic chart highlighting new play potential. 

Louisiana

Texas

Mississippi Alabama

Florida

Mississippi Fan

Foldbelt play

Sigsbee Escarpment

Perdido Foldbelt play

Composite outline of Eastern GOM plays

(Pleistocene through Jurassic)

Trident & 

Great White

f f f f f f f f f f f fff f f f

Chinook

St. Malo

Cascade

Paleogene Reservoirs

50 0 50 mi

50 0 50 km

1000 ft

1500 ft

5000 ft

7500 ft

Figure 6. Frontier plays in the deepwater GOM. 
12 

deepwater plays in the GOM, the Mississippi Fan Foldbelt and the Perdido Foldbelt, which include 

reservoirs of Paleogene age. Announced discoveries in the Alaminos Canyon area (Trident and Great 

White) and in the Walker Ridge area (St. Malo, Cascade, and Chinook) provide evidence of productive 

Paleogene reservoirs in a wide area of the deepwater GOM. However, many important questions remain 

concerning the extent and producibility of these older reservoirs. 

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

Pleistocene through Jurassic. Successful exploration has occurred in the Eastern GOM with announced 

discoveries in DeSoto Canyon (Spiderman/Amazon), in Lloyd Ridge (Atlas), and in Atwater Valley 

(Jubilee). 

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

territory.” During the last three years there have been 11 industry-announced discoveries in water depths 

greater than 7,000 ft (2,134 m) (table 1). Announced volumes for these discoveries are more than 

1.75 billion BOE. 

Table 1 

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 

AC = Alaminos Canyon 

AT = Atwater Valley 

DC = DeSoto Canyon 

LL = Lloyd Ridge 

MC = Mississippi Canyon 

WR = Walker Ridge 

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. 
13 

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

in gas hydrates (figure 7). 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. 

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 other 

marine settings around the world. Thermogenic gas hydrates are derived from deeply buried, organic-rich 

sediments or existing gas reservoirs and contain a mixture of complex hydrocarbon gases. Biogenic gas 

hydrates are generated at shallow depths by bacterial decomposition of organic matter, yielding primarily 

methane gas. Gas-hydrate mounds (figure 8) and associated chemosynthetic communities, commonly at 

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

sites in the GOM. 

There are many unanswered questions 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, a joint effort by MMS, Department of Energy 

(DOE), and seven oil and service companies will begin in 2004. Approximately eight 1,000- to 2,000-ft 

(305- to 610-m) deep wells will be drilled, logged, and cored through bedded hydrates near seafloor 

hydrate mounds in Atwater Valley and Keathley Canyon. This project will allow the first calibration of 

geophysical data for characterizing buried gas hydrates in the GOM. The MMS is developing a gashydrate assessment model and will complete an initial inventory of the amount of recoverable hydrates in 

2005. 

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, several key deepwater discoveries, the 

recognition of high deepwater production rates, and the evolution of deepwater development 

technologies. 

The GOM leasing status is shown in figure 10. There are about 3,600 active leases in water depths less 

than 1,000 ft (305 m), about 150 active leases in 1,000-1,499 ft (305-457 m) of water, about 1,800 active 

leases in 1,500-4,999 ft (457-1,524 m) of water, about 1,500 active leases in 5,000-7,499 ft 

(1,524-2,286 m) of water, and about 750 active leases in water depths of 7,500 ft (2,286 m) and greater. 

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 C provides a chronological listing of all Gulf of Mexico lease offerings 

arranged by sale number, location, and date. 

Figure 11 shows the historic total active leasing trends by water-depth range. Notice the dramatic 

increase in active deepwater leases from 1995 through 1998. In 1999, the number of active deepwater 

leases surpassed that of shallow-water leases. 

Operators contend with numerous obstacles when venturing into the deepwater arena. Figure 12 

illustrates natural features and manmade zones that require special considerations for oil and gas 

activities. Although the topographic features are located primarily along the shelf break, they may be 

obstacles to pipelines from deepwater developments to the shelf infrastructure. 
14

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25 

25 

Figure 7. Location of known gas hydrates in the Gulf of Mexico. 
15

Figure 8. Gas hydrates on the seafloor in Green Canyon Block 185 (photo courtesy of GERG/Texas A&M University). 
16 

Texas

Louisiana

Mississippi Alabama

Florida

1000 ft

1500 ft

5000 7 ft 500 ft

Texas

Louisiana

Mississippi Alabama

Florida

1000 ft

1500 ft

7

5000 ft 500 ft

Texas

Louisiana

Mississippi Alabama

Florida

1000 ft

1500 ft

7500 ft 5000 ft

50 0 50 km

50 0 50 mi

1992 - 1993

1994 - 1995

1996 - 1997

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

Texas

Louisiana

Mississippi Alabama

Florida

1000 ft

1500 ft

75

5000 ft 00 ft

Texas

Louisiana

Mississippi Alabama

Florida

1000 ft

1500 ft

7

5000 ft 500 ft

Texas

Louisiana

Mississippi Alabama

Florida

1000 ft

1500 f

5

t

75

000 ft 00 ft

1998 - 1999

2000 - 2001

50 0 50 km

50 0 50 mi

2002 - 2003

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

_

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

Eastern Planning Area Eastern Planning Area

Florida

Mississippi Alabama

Louisiana

Texas

Western Planning Area Central Planning Area

Ge

5000 ft 7500 ft

1500 ft

Ge

Florida

Mississippi Alabama

Louisiana

Texas

Western Planning Area

1000 ft

Active leases by water depth

50 0 

50 0 

46%

10%

2%

<1,000 ft

1,000 - 

1

_

>7,500 ft

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

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

Year

Number of Active Leases

< 1,000 ft All deepwater 1,000-1,499 ft

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

Water Depth (ft) 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 

< 1,000 ft 3,645 3,613 3,886 4,228 4,162 3,716 3,588 3,531 3,382 3,585 

1,000-1,499 ft 121 129 166 189 199 185 179 162 153 150 

1,500-4,999 ft 886 988 1,300 1,683 1,753 1,632 1,537 1,627 1,703 1,793 

5,000-7,499 ft 278 323 614 1,084 1,293 1,289 1,283 1,314 1,432 1,506 

> 7,500 ft 102 109 214 429 727 744 761 822 821 757 

Total Number 

Leases 5,032 5,162 6,180 7,613 8,134 7,566 7,348 7,456 7,491 7,791 

Figure 11. Total active leases by water depth. 
20

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5000 ft

7500 ft

%[ Inactive radioactive ocean disposal site$

Lightering zone (single-hulled tankers)Topographic features (reef or bank)Flower Garden Banks oil spill notification zone

50 0 

50 0 

Figure 12. Environmental and deepwater administrative features. 
21 

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 18 areas or "grids" of biological similarity (figure 13). 

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 

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 National Environmental Policy Act’s (NEPA's) implementing regulations. 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 2 below shows the status of the grid PEA’s. 

Table 2 

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. 
22

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5000 ft

1000 ft 1500 ft

Central Planning Area

Louisiana

$T$ Deepwater discovery

50 0 

50 0 

Grid boundaryGrid EA completed

Figure 13. Grid EA status. 
23 

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 has a surface structure in 

one of the 18 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 14 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. 

The deepwater GOM has an amazing diversity of about 20 species of whales and dolphins (cetaceans), 

including the endangered sperm whale. Sperm whales are the deepest diving cetacean, routinely engaging 

in 45-to-60-minute dives while chasing prey (predominately large squid) in 2,300-3,300 ft (701-1,006 m) 

of water. Approximately 1,000 sperm whales can be found in the northern GOM. They are rarely seen in 

less than 2,300 ft (701 m) of water, and most likely are found at about 3,300-ft (1,006-m) water depths. 

Although the whales move throughout the deeper Gulf, one preferred area is off the Mississippi River 

delta – an area with considerable oil and gas activity. 

Sperm whales, like the majority of cetaceans, depend more on hearing than on vision to navigate, 

communicate, and find food. They have complex sound-producing organs and equally complex soundreception and sound-processing capabilities. Since airguns create intense sound waves, there is concern 

that seismic surveys could damage whales’ hearing or interfere with their communications and biological 

sonar. To date, there are no definitive data demonstrating the effect that airguns have on sperm whales 

and other cetaceans. However, preliminary findings from ongoing studies suggest that sperm whales do 

not react to moderate levels of airgun exposure. 

To mitigate potential impacts, MMS has engaged in a precautionary approach to regulating seismic 

operations. New rules require seismic vessels to 

• start airgun operations during daylight hours only, 

• ramp up airguns slowly when operations begin, 

• visually monitor for sperm whales within a 1,640-ft (500-m) radius, and 

• halt airgun operations if sperm whales are seen within a 1,640-ft (500-m) radius. 

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 15). 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. 
24

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50 0 

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Figure 14. ROV surveys including known chemosynthetic communities. 
25

Figure 15. Loop and eddy currents in the Gulf of Mexico (image courtesy of Horizon Marine, Inc.). 
26 

Beneath the 3,000-ft (914-m) water depth, other currents migrate around the deep waters of the GOM. 

Until recently, these deep currents were thought to be minimal and were not a major consideration in most 

structure designs. In 1999, industry reported significant currents on the OCS below 3,000 ft (914 m). 

This information led to a Safety Alert and subsequent study of deep currents by MMS (Hamilton et al., 

2003). This study revealed significant deep currents of up to 2 kn at some locations. The effects of all 

currents must be considered in the design of deepwater floating production facilities, drilling rigs, and 

their ancillary equipment, such as steel catenary risers and mooring systems. 

Recent incidents have revealed the need for more accurate data in hind-casting and forecasting events and 

in daily operations. As a result, MMS is proposing to issue an NTL titled “Ocean Current Monitoring on 

Floating Facilities.” This NTL could establish and implement a program where operators of deepwater 

offshore production facilities and mobile offshore drilling units (MODU’s) collect data on ocean currents 

and submit them for publication on an industry-sponsored Internet website. Data collected on currents 

will improve fatigue forecast models and establish responsible design criteria, resulting in increased 

reliability of deepwater structures, thereby reducing risk to human lives, offshore facilities, and the ocean 

environment. 

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 16 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. Note that the last frame 

of this figure only represents a 3-year span and that several recent discoveries are not shown in this frame 

because they have not been assigned a discovery date yet. (The Reserves and Production section of this 

report explains how discovery dates are assigned.) 

Figure 17 shows how major and nonmajor oil and gas companies compare in terms of deepwater project 

discoveries. (Appendix E lists those companies defined as majors.) 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. 

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 18 illustrates the estimated sizes and distributions of 

80 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 recently 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 19). 

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 20). Although 

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

concentrated in southeastern Louisiana. 

Figure 21 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 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. 
27 

$

$$ $$ $$

1000 ft

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7500 ft

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Florida

Mississippi Alabama

Louisiana

Texas

$ $ $ $

$

$ $$ $ $ $ $ $ $

1000 ft

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Florida

Mississippi Alabama

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Texas

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1000 ft

1500 ft

7500 ft

5000 ft

Florida

Mississippi Alabama

Louisiana

Texas

50 0 50 km

50 0 50 mi

1975 - 1979

1980 - 1984

1985 - 1989

Figure 16. Deepwater discoveries in the Gulf of Mexico. 
28 

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1000 ft

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7500 ft

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Florida

Mississippi Alabama

Louisiana

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Florida

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Louisiana

Texas

1990 - 1994

1995 - 1999

2000 - 2003

50 0 50 km

50 0 50 mi

Figure 16. Deepwater discoveries in the Gulf of Mexico (continued). 
29

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Deepwater Discoveries

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25 

Figure 17. Ownership of deepwater discoveries (includes industry-announced discoveries). 
30

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#S #S #S #S

#S #S #S

#S #S #S #S #S

#S

#S

#S#S

Louisiana Mississip

Texas

7500 ft

5000 ft

1500 ft 1000 ft

#S 5- 50

#S 50 - 150

#S 150 - 300

#S 300 +

Reserves

(million BOE)

50 0 

50 0 

Figure 18. Estimated volumes of 80 proved deepwater fields. 
31

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7500 ft

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VENICE

CAMERON

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PORT

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Ñ Pascagoula

ð Port Aransas %[ Venice

Existing Deepwater Structures and Corresponding Service Bases

$T Galveston

50 0 

50 0 

Figure 19. Onshore service bases for existing deepwater structures. 
32

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AMELIA FT. JACKS

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DULAC

PORT O'CONNOR

Pending Plans and Corresponding Service Bases

%U#Y

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$T Galveston - 6%

#3 Other (Amelia, Dulac, Fort Jackson, Freeport

Grand Isle, Houma, Leeville, Morgan City, Port O' Connor, Venice) - 24%

50 0 

50 0 

Figure 20. Onshore service bases for pending deepwater plans. 
33

%U%U%U

Deepwater facilities that currently act as a hub or have the potential to act as a hub.Future deepwater facilities that will have the potential to be used as a hub once they are installed.Shallow-water facilities that currently act as a hub.

Facilities

% Other (compliant tower, FPS, fixed platform, or semi-submersible)$ Spar

#System Type

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Louisiana Mississippi Ala

Texas

Central Planning Area

7500 ft

5000 ft

1000 ft 1500 ft

Western Planning Area

50 

50 

Figure 21. Current, potential, and future hub facilities in the Gulf of Mexico. 
34 

The infrastructure needed to bring deepwater production online continues to develop over time. Figure 22 

shows the framework of major oil and gas pipelines in the GOM. Figure 23 illustrates the existing 

network of deepwater pipelines. These figures highlight new and proposed pipelines since the last report. 

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 3 shows proposed LNG 

terminals in the GOM. 

Table 3 

LNG Projects Proposed in the Gulf of Mexico 

Project Name Company Area and Block Facility Type 

Port Pelican Port Pelican LLC 

(ChevronTexaco) 

Vermilion 140 Concrete Gravity 

Base Structures 

Energy Bridge El Paso Energy Bridge GOM, LLC 

(El Paso) 

West Cameron 603 Submerged Turret 

Loading Buoy 

Gulf Landing Gulf Landing, LLC 

(Shell) 

West Cameron 213 Gravity Base 

Structures 

Main Pass 

Energy Hub 

Freeport-McMoRan Energy, LLC 

(Freeport-McMoRan) 

Main Pass 299 Incorporates Existing 

Platforms 
35

Mississip

Louisiana

Texas

7500 ft

5000 ft

1500 ft 1000 ft

PipelinesNew pipelinesProposed pipelines

50 0 

50 0 

Figure 22. Oil and gas pipelines with diameters greater than or equal to 20 inches. 
36 

Mississippi Alabama

Louisiana

Texas

7500 ft

5000 ft

1500 ft 1000 ft

Mississippi Alabama

Louisiana

Texas

7500 ft

5000 ft

1500 ft 1000 ft

OIL

GAS

Deepwater Pipelines

Existing New Proposed

50 0 50 mi

50 0 50 km

Figure 23. Deepwater oil and gas pipelines in the Gulf of Mexico. 
37 

LEASING 

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). For example, in 

1992 there were 176 leases issued in water depths less than approximately 650 ft (200 m), compared with 

only 28 leases issued in water depths greater than that depth. 

In 1995, the DWRRA established incentives for royalty relief based on water-depth intervals defined in 

meters. The water-depth categories depicted in figure 24 reflect the divisions used 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. In 1992, for example, leases in water depths greater than 800 m (2,625 ft) only accounted for 

3 percent of leases issued. By the end of 1998, however, this had grown to almost 70 percent. 

While interest in deepwater blocks increased during the mid-1990’s, interest in shallow-water blocks 

faded during that period. For example, shelf leases accounted for 86 percent of all leases issued in 1992, 

but this dropped to 23 percent by the end of 1998. 

BIDDING AND LEASING TRENDS

The Gulf experienced a lull in leasing activities in 1999 — about a four-fold decrease compared with the 

1998 levels. However, interest is rekindling in blocks in the 200-m (650-ft) or less range and in the 

greater than 800-m (2,625-ft) range, evidenced by increased leasing activities in the 1999-2003 interval. 

Note that shelf leasing has once again outpaced leasing in water depths greater than 800 m (2,625 ft). 

Some of the resurgent interest in the shelf area may be the result of the MMS’s recent royalty suspension 

program for new deep-gas development in water depths less than 200 m (650 ft). Data in figure 24 

include 95 leases awarded in Sale 181 (2001) and 14 leases in Sale 198 (2003), both Eastern GOM sales. 

All of the leases in these Eastern GOM sales are located in water depths of 1,600 m (5,250 ft) or greater. 

Figure 25a was derived from the data in figure 24 but displays the deepwater categories used elsewhere in 

this report (shallow-water data are excluded from figure 25a). These deepwater data show the rapid 

increase in leasing activity that began in 1995. Although GOM leasing activity plummeted in 1999, there 

has since been a steady increase in leases awarded in the 1,500-4,999 ft (457-1,524 m) and the 

5,000-7,499 ft (1,524- 2,286 m) intervals since that time. 

Figure 25b shows the total amount of money spent annually for leases in each water-depth range. Large 

financial investments were made by the oil and gas industry from 1996 through 1998. Bid amounts were 

depressed in 1999, moderately increased to 2001, and slightly decreased since that time. 

Most important for lease trend analysis is the average bid amount per lease as depicted in figure 25c. 

Overall, the average bid price for all deepwater leases steadily increased from 1992 through 2001. 

Beginning in 2002, there was a downturn in average bid amount per deepwater block. The high average 

bid amounts for 2001 reflect the fact that the industry bid large amounts per block for leases in the 

Eastern GOM. This was the first opportunity in 16 years for companies to bid in an area immediately 

adjacent to discoveries in the Central GOM area. 

As the value of deepwater leases increased throughout the 1990’s, MMS rejected an increasing number of 

deepwater high bids that it viewed as insufficient. Figure 26 shows that tracts with rejected bids moved 

into increasingly deeper waters over time. The rejection trend reflects the fact that, as more deepwater 

fields began production, they provided analogs (with high production rates, thick reservoir sections, and 

production infrastructure) and thus reduced the risk on similar deepwater blocks, leading to an increase in 

the estimated net present worth of the unleased deepwater blocks. 
38

509

466

261

176

165

325

453

418

525

620

265

4

15

25

33

16

14

44

35

66

52

103

110

99

58

17

74

28

36

30

17

712

171

135

186

1,110

771

382

7

24

39

0

200400600800

1,0001,200

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 

Year

Number of Leases Issued

< 200 m 200-400 m 400-800 

Figure 24. Number of leases issued each year, subdivided by DWRRA water-depth categories. 
39

0

100200300400500600

Number of Leases Bid On

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

Lease Sale Year

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

DWRRA postDWRRA

Figure 25a. Number of leases bid on for each deepwater 

interval. 

$0

$100$200$300$400$500$600

Bids in Millions of Dollars

1992 1993 1994 1995 1996 1997 1998 

Lease Sale Year

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

D

Figure 25b. Total bid amounts in deepwater in

-

0.501.001.502.002.503.003.50

Average Bid Amount in

Millions of Dollars

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 

Lease Sale Year

1,000-1,499 ft1,500-4,999 ft 5,000-7,499 ft>7,500 ft

DWRRA postDWRRA

Figure 25c. Average bid amount per block in deepwater intervals. 
40 

1000 ft

1500 ft

7500 ft

5000 ft

Florida

Mississippi Alabama

Louisiana

Texas

1000 ft

1500 ft

7500 ft

5000 ft

Florida

Mississippi Alabama

Louisiana

Texas

1992 - 1993

1994 - 1995

1000 ft

1500 ft

7500 ft

5000 ft

Florida

Mississippi Alabama

Louisiana

Texas

1996 - 1997

50 0 50 km

50 0 50 mi

Figure 26. Rejected shallow- and deepwater Gulf of Mexico bids. 
41 

1000 ft

1500 ft

7500 ft

5000 ft

Florida

Mississippi Alabama

Louisiana

Texas

1000 ft

1500 ft

7500 ft

5000 ft

Florida

Mississippi Alabama

Louisiana

Texas

1000 ft

1500 ft

7500 ft

5000 ft

Florida

Mississippi Alabama

Louisiana

Texas

1998 - 1999

2000 - 2001

50 0 50 km

50 0 50 mi

2002 - 2003

Figure 26. Rejected shallow- and deepwater Gulf of Mexico bids (continued). 
42 

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. 

Appendix E shows the companies and subsidiaries that form these majors. (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 27 illustrates the relative leaseholding 

positions of majors versus nonmajors. (Figure 27 reflects the most recent lease ownerships at the end of 

each 2-year period.) Note that majors dominated deepwater leasing in 1992-1993. In 1996, nonmajors 

began acquiring significant leaseholdings, a trend that continued through 2003. Nonmajor companies are 

poised to play a leading role in the future of the deepwater Gulf. 

The type of companies active in deepwater clearly changed with the increased presence of nonmajor oil 

and gas companies. Another change in deepwater lease ownership came with the wave of company 

mega-mergers. The industry mergers increased the diversity of leaseholdings for the merged companies. 

For example, while some companies were heavily focused on the deepwater GOM prior to the mergers, 

their merger partners may have been focused primarily on shallow-water prospects. The combination of 

these entities yielded a larger leasehold position in all water depths and frequently a broader geographic 

range across the GOM. 

FUTURE LEASE ACTIVITY

Since the deepwater arena is already heavily leased, the number of leases that are relinquished or expire 

will influence activity in future lease sales. Given the fact that most companies can only drill a small 

percentage of their active leases, it is likely that many high-quality leases will expire without being tested. 

The impending turnover of these leases often results in “farm-outs” to nonmajors, opportunities for 

different companies to gain a lease position and, potentially, a more rapid exploration and development of 

the acreage. Ultimately, an untested and undeveloped lease will expire and possibly be leased again. 

Figure 28 shows leases that will 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 

400-799 m (1,312-2,622 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 2010 

(explaining the absence of expiring shallow-water leases in certain frames of figure 28). The 2003 and 

2004 lease sales will offer a limited number of expired deepwater leases because of moderate leasing 

activity in 1993 and 1994. The availability of previously leased blocks is expected to increase 

dramatically in 2006 as a result of the leasing boom that began in 1996 and continued through 1998. The 

lease expiration projections will pressure leaseholders to drill and evaluate their holdings and will provide 

opportunities for other companies to enter an active play by acquiring leases as they expire or by 

obtaining “farm-outs” from companies with untested acreage. 
43 

Florida

Mississippi Alabama

Louisiana

Texas

1000 ft 1500 ft

7

5

5

000 ft 00 ft

Florida

Mississippi Alabama

Louisiana

Texas

1000 ft 1500 ft

7

5

5

000 ft 00 ft

Florida

Mississippi Alabama

Louisiana

Texas

1000 ft 1500 ft

7

5

5

000 ft 00 ft

1992 - 1993

1994 - 1995

1996 - 1997

50 0 50 mi

50 0 50 km

Leases with greater than

50% major ownership

Leases with 50%

major ownership

Leases with less than

50% major ownership

112 332

1,297

Figure 27. Ownership of deepwater leases. 
44 

1000 ft 1500 ft

7

5

5

000 ft 00 ft

Texas

Louisiana

Mississippi Alabama

Florida

1000 ft 1500 ft

7

5

5

000 ft 00 ft

Texas

Louisiana

Mississippi Alabama

Florida

Florida

Mississippi Alabama

Louisiana

Texas

1000 ft 1500 ft

7

5

5

000 ft 00 ft

1998 - 1999

2000 - 2001

2002 - 2003

Leases with greater than

50% major ownership

Leases with 50%

major ownership

Leases with less than

50% major ownership

50 0 50 mi

50 0 50 km

183

1,974

2,348

Figure 27. Ownership of deepwater leases (continued). 
45 

Florida

Mississippi Alabama

Louisiana

Texas

1000 150 ft 0

50

ft

00 ft 7500 ft

Florida

Mississippi Alabama

Louisiana

Texas

5000 ft 7500 ft

1000 150 ft 0 ft

2004 - 2005

(741 leases)

2006 - 2007

(2,527 leases)

Florida

Mississippi Alabama

Louisiana

Texas

5000 ft 7500 ft

1000 150 ft 0 ft

2008 - 2009

(1,077 leases)

50 0 50 mi

50 0 50 km

Figure 28. Anticipated lease expirations in the Gulf of Mexico. 
46 

Florida

Mississippi Alabama

Louisiana

Texas

1000 150 ft 0

50

ft

00 ft 7500 ft

Florida

Mississippi Alabama

Louisiana

Texas

5000 ft 7500 ft

1000 150 ft 0 ft

50 0 50 mi

50 0 50 km

2010 - 2011

(558 leases)

2012 - 2013

(525 leases)

Figure 28. Anticipated lease expirations in the Gulf of Mexico (continued). 
47 

DRILLING AND DEVELOPMENT 

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

or drillships (figures 29 and 30), and from platform rigs. There are numerous deepwater prospects 

waiting to be drilled, and there will be many that remain undrilled before the primary lease terms expire 

because of the limited number of rigs available for deepwater drilling in the GOM. Figure 31 depicts 

deepwater rigs operating in the GOM from 1992 through 2003.1

 There was a steady increase in the 

average number of rigs operating from 1992 to a peak in 2001. However, in the past two years, the 

number of rigs operating has decreased 29 percent. Figure 32 shows the number of deepwater MODU’s 

by water-depth categories in the GOM and worldwide. Approximately 28 percent of the world’s fleet of 

deepwater drilling rigs is committed to GOM service (Harding and Albaugh, 2003). The pie chart within 

figure 32 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 any conclusions from the rig count differences between figures 31 and 32. As mentioned 

above, figure 31 includes platform rigs in addition to MODU’s; figure 32 addresses MODU’s only. 

Further, not all MODU’s in figure 32 are operating at any given time and upgrades to MODU’s that 

increase their water-depth capability will alter the rig counts shown, so 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 the last two 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 33 shows that most of the drilling has 

occurred in the 1,500- to 4,999-ft (457- to 1,524-m) water-depth range. Despite an overall decline in 

recent years, considerable drilling activity occurred in water depths greater than 7,500 ft (2,286 m). It is 

interesting to note that, in November 2003, the first well began drilling in over 10,000 ft (3,050 m) of 

water and more are anticipated. 

Figures 34 and 35 further break down the deepwater well counts 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. In the past two years, there has been a decrease in the number of exploratory wells drilled. 

This is best illustrated by looking at the number of wells drilled in the 1,500- to 4,999-ft (457- to 

1,524-m) water-depth range. While exploratory drilling at this depth is decreasing, drilling in the 5,000- 

to 7,499-ft (1,524- to 2,286-m) and the >7,500 ft (2,286 m) water-depth ranges is increasing. There has 

also been a decrease in the number of development wells drilled in the last year. Possible reasons for the 

recent 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 was in the 1,500- to 

4,999-ft (457- to 1,524-m) water-depth range; there are no development wells in water depths exceeding 

7,500 ft (2,286 m). 

Figure 36 illustrates the geographic distribution of deepwater exploratory wells. Note the progression 

into the western GOM and into deeper water through time. Figure 37 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. 

 

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. 
48

Figure 29. The Deepwater Horizon, a dynamically positioned, semisubmersible drilling unit (photo courtesy of Transo
49

Figure 30. The Discoverer Deep Seas, a Class 1A1, double-hulled, dynamically positioned drillship (photo courtesy of 
50 

3

6

11

14

18

26

28 28

33

41

36

29

25 25 25

0

10

20

30

40

50

Average Number of Deepwater Rigs Operating

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006

Year

Figure 31. Average number of rigs operating in the deepwater GOM. (White bars are 

estimates.) 

3

12

18

75

12

38

11

32

0

10

20

30

40

50

60

70

80

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

Brazil 2 9

GOM 44

W. Africa 

16

North Sea 

3 1

Other 3 7

Figure 32. 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. 
51

2110

1

2715

1

1945

1

2556

3

2475

6

1

32

132

12

33

124

10

1

14

119

37

30

143

25

9

25

126

53

6

2

1

3

0

50

100150200250

Number of Wells Spudded

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 200

Year

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

32

43

65

84

106

176

168 170

207

210

Figure 33. All deepwater wells drilled in the Gulf of Mexico, subdivided by water depth. 
52

1

3

1

3

15

7

38

1

8

38

2

7

50

6

1

1781

9

2088

9

1

106131

8

6716

9

5

7330

6

0

20406080

100120

Number of Wells Spudded

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 20

Year

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

Number of leases tested

5

18

46 48

64

107

118

102 100

114

Figure 34. All deepwater exploratory wells drilled in the Gulf of Mexico by water depth. 
53

20

7

24

1

12

7

1718

1

1725

1551

3

1336

1

4

58

6

2276

9

205323

181

0

20406080

100120

Number of Wells Spudded

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 200

Year

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

27 25

19

36

42

69

50

68

107

96

1

Figure 35. Deepwater development wells drilled in the Gulf of Mexico, divided by water depth. 
54 

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Louisiana

Texas

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1000 ft

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Florida

Mississippi Alabama

Louisiana

Texas

$

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$

1000 ft

1500 ft

7500 ft

5000 ft

Florida

Mississippi Alabama

Louisiana

Texas

1992 - 1993

1994 - 1995

50 0 50 mi

50 0 50 km

1996 - 1997

Figure 36. Deepwater exploratory wells drilled in the Gulf of Mexico. 
55 

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2002 - 2003

Figure 36. Deepwater exploratory wells drilled in the Gulf of Mexico (continued). 
56 

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Figure 37. Deepwater development wells drilled in the Gulf of Mexico. 
57 

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50 0 50 km

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2002 - 2003

Figure 37. Deepwater development wells drilled in the Gulf of Mexico (continued). 
58 

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 Preliminary DWOP, 

• drill development wells, then 

• begin production. 

Figure 38 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 and DOCD’s includes initial, 

supplemental, and revised plans; only the initial submittals (Conceptual Part) of the DWOP’s are shown. 

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 shallow-water marginal 

developments. 

There was a marked increase in EP’s, DOCD’s, and DWOP’s beginning in 1996. In recent years, 

however, there has been a moderate decrease in these plans. 

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

[TVD]). Since 1996 the maximum drilling depth has increased rapidly, reaching depths below 30,000 ft 

(9,144 m) in 2002. Figure 39 shows the maximum TVD of wells drilled each year since 1965. The 

maximum TVD increased gradually from 17,500 ft (5,334 m) in 1965 to 26,978 ft (8,223 m) in 1998. 

The recent dramatic increase in TVD to a record 31,824 ft (9,700 m), reached in 2003, may be attributed 

to several factors, including enhanced rig capabilities, deeper exploration targets, and the general trend 

toward greater water depths. 

Figure 40 shows the maximum water depth drilled in the entire GOM each year since 1965. The 

progression into greater water depths has been very rapid. Deepwater drilling began in 1975; significant 

water depth records occurred in 1976 (1,986 ft or 605 m), 1983 (3,530 ft or 1,076 m), and 1987 (7,500 ft 

or 2,286 m). In November 2003, ChevronTexaco set a world record – drilling in 10,011 ft (3,051 m) of 

water at its Toledo prospect in Alaminos Canyon Block 951. 

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 41 shows the different systems that can be used to 

develop deepwater discoveries. Table 4 lists the systems that have begun production. In contrast to the 

MMS field designations used in the 2002 report, table 4 now lists operator-designated project names. 

Fixed platforms (e.g., Bullwinkle) have economic water-depth limits of about 1,400 ft (427 m). 

Compliant towers (e.g., Petronius) may be considered for water depths of approximately 1,000-3,000 ft 

(305-914 m). Tension-leg platforms (TLP’s) (e.g., Brutus and Typhoon) are frequently used in 1,000- to 

5,000-ft (305- to 1,524-m) water depths. Spars (e.g., Genesis), 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 42 shows three of these 

development systems: a TLP, a spar, and a semisubmersible. 
59

25

3

25

4

35

4

38

75

64

10

19

105

11

32

125

16

24

152

14

26

158

26

34

144

35

40

142

0

20406080

100120140160180

Number of Plans Received

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2

Year

Deepwater EPDeepwater DOCDDWOP

Figure 38. Deepwater EP's, DOCD's, and DWOP's received in the Gulf of Mexico since 1992. 
60

18,507

22,840

20,000

19,533

18,385

19,488

17,229

20,000

17,388

20,988

18,002

20,400

19,539

20,450

23,264

21,068

25,000

23,191

22,680

22,885

24,650

25,450

22,807

22,263

21,736

17,500

22,887

23,066

22,892

24,274

19,000

21,988

24,084

0

5,000

10,00015,00020,00025,00030,00035,000

1965 1971 1977 1983 1989 1995 

Year

Maximum Well TVD (ft)

Figure 39. Maximum wellbore true vertical depth (TVD) drilled in the total Gulf of Mexico each year. 
61

340

626

390

472

472

456

393

475

590

696

1,986

1,895

1,363

2,211

1,835

3,534

3,135

5,400

7,500

6,950

6,660

5,834

5,149

6,530

6,420

6,240

7,620

6,740

7,500

1,793

1,747

1,790

3,530

0

2,0004,0006,0008,000

10,00012,000

1965 1971 1977 1983 1989 1995 

Year

Maximum Water Depth (ft)

Figure 40. Maximum water depth drilled each year. 
62 

Figure 41. Deepwater development systems. 
63 

Table 4 

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 

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 
64 

Table 4 

Development Systems of Productive Deepwater GOM Projects 

Year of 

First 

Production 

Project 

Name2 Operator Block 

Water 

Depth 

(ft) 

System Type DWRR3

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 

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 Kerr McGee EB 643 3,650 Spar Yes 

2002 Camden Hills Marathon MC 348 7,216 Subsea Yes 

2002 Horn Mountain BP MC 127 5,400 Spar Yes 

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 Spar Yes 

2002 Navajo Kerr McGee EB 690 4,210 Subsea Yes 
65 

Table 4 

Development Systems of Productive Deepwater GOM Projects 

Year of 

First 

Production 

Project 

Name2 Operator Block 

Water 

Depth 

(ft) 

System Type DWRR3

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 Boris BHP GC 282 2,378 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 Goose Spinnaker MC 751 1,624 Subsea 

2003 Gunnison Kerr McGee GB 668 3,100 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 Pardner Anadarko MC 401 1,139 Subsea 

2003 Zia Devon MC 496 1,804 Subsea 

1

 Indicates projects that are no longer on production. 

2

 The previous edition of this report listed deepwater fields, whereas this version lists deepwater projects. The 

Definitions section of this report explains the difference between a field and project. 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 
66

Figure 42. Three different development systems (left to right): a SeaStar TLP installed at ChevronTexaco’s Typ

installed at ChevronTexaco’s Genesis Field, and a semisubmersible at Shell/BP’s Na Kika Field (im

ChevronTexaco, Shell International Exploration and Production Inc., and BP). 
67 

A predominant workhorse of the GOM is the 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 midsection structure hanging from the hard tanks, and a stabilizing keel section at the bottom. 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 up to 10,000 ft (3,048 m) and beyond. 

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 43). 

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 both 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. Other examples of a classic spar are Genesis and Hoover. 

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. Other 

examples of the truss spar are Boomvang, Horn Mountain, and Devil’s Tower. Once installed, Devil’s 

Tower will be the deepest spar, operating at a water depth of 5,610 ft (1,710m). 

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 are required). 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. The first cell 

spar will be installed in the Red Hawk field in 5,300 ft (1,615 m) of water in late 2004. 

Figure 44 shows the different types of production systems installed each year. Data values can be found 

in Appendix F. At least eight deepwater production facilities (primarily truss spars) are under 

construction or pending installation at this time. 
68

Figure 43. Progression of spar deepwater development systems (image courtesy of Technip-Coflexip). 

L = length DIA = outside diameter W.D. = water depth 
69

1979

1984

1989

1994

Fixed Platform

Compliant Tower

Semi-FPS

Truss Spar

Spar

Small TLP

TLP

0

1

2

3

Number Installed

Year

Subsea (92)

TLP (14)

Compliant 

Tower (3) Fixed Platform 

(5)

Spar (12)

Semi-FPS (5)

Figure 44. GOM deepwater production facilities installed each year (including plans through 2006). Inset show

systems for currently producing fields (including subsea systems). 
70 

Subsea systems, as shown in figure 45, 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 for 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. 

SUBSEA TRENDS

Figure 46 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 within figure 46 shows that shallow-water subsea wells 

are a significant contribution to the subsea well population in the GOM. Shallow-water subsea wells 

accounted for 131 of the 295 total subsea wells in the GOM by yearend 2003. Operators have found 

subsea tiebacks to be valuable for shallow-water marginal fields because of the extensive infrastructure of 

platforms and pipelines. Nonmajor companies have installed nearly all of these shallow-water subsea 

wells, led by Walter Oil and Gas Corporation with 35 wells. Figure 46 demonstrates the increasing 

reliance of industry on subsea technology to develop both 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 decade. This evolution is apparent in figure 47, which shows 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). Camden Hills has the deepest production in the GOM to date, in a water depth of 

7,216 ft (2,199 m). A listing of productive subsea completions on the GOM Outer Continental Shelf can 

be found in Appendix G. 

Figure 48 further breaks down the subsea completion count into specific water depth ranges. This figure 

shows that 70 percent of the subsea completions are in water depths less than 2,500 ft (762 m). 

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 49. 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 50a and 50b. The data include the 

total length of all pipelines originating at a deepwater development, including any shallow-water 

segments (control umbilicals are excluded). Figure 50a 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 — 58 percent of the total since 1990. The large increase in 2001 in both 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. 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 50b). The peak in 2002 was driven by the approval of the Mardi Gras system. 
71

Subse

Subsea Manifold

Flow line jumper

EHCU

Well # 1

Well # 2

Well # 3

Subsea Umbilical Termination Assembly (SUTA)

Flow lines to host platform

Figure 45. Crosby Project (MC 899) subsea equipment layout (image courtesy of Shell International Exploration and 
72 

0

5

10

15

20

25

30

35

40

1955 1960 1965 1970 1975 1980 1985 1990 1995 2000

Year

Number of Subsea Completions

shallow water

deepwater

deepwater

56%

shallow water

44%

Figure 46. 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

Year

Maximum Water Depth (ft)

King's Peak

Mensa

Mars

GC 31

HI A573

Camden Hills

Figure 47. Maximum water depth of subsea completions each year. 
73 

131

78

60

20

6

0

20

40

60

80

100

120

140

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 48. Water depth of subsea completions. 

83

38

34

5 4 2

0

10

20

30

40

50

60

70

80

90

Number of Pipeline Segments

< 5 5 - 9 10 - 19 20 - 29 30 - 49 50+

Tieback Length Range (mi)

Figure 49. Length of subsea tiebacks. 
74 

26 20

39 45 12

65

121

18

32 42

173

95

56

121

97

108

62

28

101

201

285

178

172

53

78

0

100

200

300

400

500

600

700

Miles of Pipelines Approved

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

Year

Gas

Oil

Figure 50a. Approved deepwater oil and gas pipelines less than or equal to 12 inches in diameter. 

50 40

41

40 39

46 103

65

179

129

25

32 41

76

300

326

157

224

0

100

200

300

400

500

600

700

Miles of Pipeline Approve

d

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

Year

Gas

Oil

Figure 50b. Approved deepwater oil and gas pipelines greater than 12 inches in diameter. 
75 

RESERVES AND PRODUCTION 

The deepwater GOM has contributed major additions to the total reserves in the GOM. Figure 51 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 1984 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 52 

includes both proved and unproved reserves for each water-depth category. This figure shows declining 

reserve additions in shallow water, similar to figure 51, 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 53 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 86 MMBOE of proved and unproved reserves. 

DISCOVERIES

Figure 54 shows the number of deepwater fields discovered each year, according to MMS criteria, since 

1975. (See appendices A and B for listings 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 late 1990’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 55 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 56 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. 
76

0

500

1,0001,5002,0002,5003,000

Million Barrels of Oil Equivalent

>7 5,1,51,0 0-

>7,500 ft. 5,000-7,499 ft. 119 60.11,500-4,999 ft. 60.8 32.5 430 58.6 493 170 1061 475 138 5.79 49.7 307 152 119 154 238 217 8.1,000-1,499 ft. 310 112 83.3 192 222 155 19.5 8.56 31.9 0-999 ft. 607 1152 1213 557 527 412 2730 876 2201 2234 1040 936 481 465 581 820 252 556 537 801 525 166 294 437 113 168 111 29.8 111 87.3 119 82.8 126 84.7 31 42

1965 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 20

Figure 51. Proved reserve additions. 
77

0

500

1,0001,5002,0002,5003,000

Million Barrels of Oil Equivalent

> 11 

>7,500 ft. 46.26 0.875 5,000-7,499 ft. 119 53 44 154 184 12 780 986 61,500-4,999 ft. 64.45 34.24 461.2 152.5 492.6 184.9 1090 569.1 156.7 5.788 57.83 522.1 205.6 166.4 168.9 720.6 428.1 161,000-1,499 ft. 310.5 126.7 84.84 192.4 259 224.8 24.75 8.564 31.85 0-999 ft. 614.3 1169 1234 576.1 546.4 414.1 2754 879.2 2240 2281 1082 994.5 484.2 516.2 602.9 843.4 256.2 566.3 542.4 841.1 546.5 187.4 308.5 548.7 114 169.8 114.7 30.87 116.8 87.95 120.1 102.8 126 97.52 36.3 48

1965 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 20

Figure 52. Proved and unproved reserve additions. 
78

0

100200300400500600700

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.

>7,500 ft. 46.26 0.875  5,000-7,499 ft. 119.5 53.48 44.08 76.97 91.93 11.95 390.2 246.6 613.1,500-4,999 ft. 64.45 11.41 115.3 50.82 164.2 46.22 272.6 142.3 156.7 5.788 57.83 130.5 68.53 41.59 28.16 120.1 61.16 32.31,000-1,499 ft. 155.2 63.36 84.84 192.4 129.5 112.4 0.294 25.48 12.37 4.282 15.93 4.765  0-999 ft. 47.26 48.72 94.93 36.01 36.43 51.77 105.9 54.95 65.88 51.83 29.25 24.26 17.93 22.44 20.1 33.74 14.23 17.7 23.58 12.02 16.56 6.94 7.524 10.97 5.43 5.305 8.824 3.858 8.984 5.497 6.674 4.893 6.3 6.501 3.025 2.54

1965 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 

Figure 53. Average field size using proved and unproved reserves. 
79

02468

1012141618

Number of Fields

1975

1976

1977

1978

1979

1980

1981

1982

1983

1984

1985

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

Field Discovery Year

Number of DiscoveriesNumber Producing

DWRRA 

Figure 54. Number of deepwater field discoveries and resulting number of producing fields. 
80

0

500

1,0001,5002,0002,5003,000

1975

1976

1977

1978

1979

1980

1981

1982

1983

1984

1985

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

Field Discovery Year

Million Barrels of Oil Equivalent

Proved ReservesUnproved reserves, resources, and industry-announced discoveriesNumber of deepwater discoveries

DWRRA

Figure 55. Number of deepwater field discoveries and new hydrocarbons found (MMS reserves, MMS resour

announced discoveries). 
81

0

500

1,0001,5002,0002,5003,000

Million Barrels of Oil Equivalent

>7,5 5,01,501,00 0-9

>7,500 ft. 50.5  5,000-7,499 ft. 119 65.3 46.3 171 227 12 780 1486 1311,500-4,999 ft. 64.5 41.3 492 241 498 198 1180 688 238 16.4 61.1 584 281 173 249 933 549 672 1,000-1,499 ft. 311 127 84.8 192 271 261 35.6 33.5 32.7 2.39 10.8 31.9 4.76  0-999 ft. 614 1185 1238 580 554 415 2765 889 2279 2303 1109 1004 493 521 615 851 278 599 577 881 577 218 338 880 153 211 164 38 120 95 149 117 142 102 40.8 65.

1965 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 200

Figure 56. BOE added (reserves, known resources, and industry-announced discoveries). 
82 

RESERVE POTENTIAL

This report has examined the history of reserve growth in the GOM. Figure 56 illustrates results of 

the latest drilling in the GOM, suggesting very significant production volumes in the near future. 

Predicting future discoveries is more difficult. To address the amount of hydrocarbons yet to be 

discovered in the GOM, this report will briefly examine one indicator — the “creaming curve” — 

and one detailed study — 2000 Assessment of Conventionally Recoverable Hydrocarbon Resources 

of the Gulf of Mexico and Atlantic Outer Continental Shelf as of January 1, 1999 (Lore et al., 2001), 

commonly known as the 2000 Assessment. 

This modified creaming curve (only successful tests are plotted), figure 57, shows the discovered and 

implies the undiscovered hydrocarbon volumes in the GOM. The creaming curve plots “cumulative 

number of fields by discovery date” against “cumulative discovered hydrocarbon volumes.” Many 

such curves demonstrate that the largest fields tend to be discovered early in the exploration cycle. 

This phenomenon results in a curve having a steep slope during the early (immature) phase of 

exploration and becoming flatter in the mature phase of exploration, when smaller fields are 

generally discovered. 

Figure 57 contains two creaming curves. The shallow-water GOM is characterized by a curve 

typical of a mature trend. The recent slope of the curve is very flat since, in general, smaller fields 

are being discovered. Unless a dramatic new exploration play is recognized, only limited reserves 

will be added. This prediction is supported by figures 51, 52, 53, and 56, all of which show a decline 

in field discovery size and added reserves from the shallow-water GOM over the last 20 years. 

The deepwater creaming curve contains fewer field discoveries; however, these fields tend to be 

large, resulting in a curve with a steep slope. This slope indicates an area that is still in an immature 

exploration phase with many large fields awaiting discovery. The limited number of discoveries, 

steep slope of the curve, and large amount of hydrocarbon volumes already discovered support this 

prediction. 

A more quantitative and geologic-based estimate of future discoveries in the GOM is the 

2000 Assessment (Lore et al., 2001), summarized in figure 58. The deepwater is expected to have 

ultimate reserves of approximately 71 billion barrels of oil equivalent (BOE), of which 56.4 billion 

BOE remains to be discovered.1

 Compare this with the shallow-water ultimate reserves of 

approximately 65 billion BOE, of which 15.2 billion BOE remain to be discovered. 

 

1

 The forecasts were based on the MMS report Atlas of Gulf of Mexico Gas and Oil Sands (Bascle, 2001). 

Each producing field and reservoir in the GOM was assigned to a hydrocarbon play. The 2000 Assessment 

(Lore et al., 2001) then forecast the number of hydrocarbons remaining to be discovered in the GOM on the 

following factors: 

• the number and size of discovered accumulations in an established play 

• an estimate of the number of undiscovered accumulations in a play 

• lognormal size distribution for these accumulations 

The MMS then predicted the size of undiscovered accumulations in each play. Frontier or conceptual plays 

were modeled on similar but more mature plays. The undiscovered accumulations were then aggregated for all 

92 plays in the 2000 Assessment. To compare reserve numbers from mature fields, recent field discoveries, and 

estimates from undiscovered fields, cumulative growth factors were used in the 2000 Assessment. It has been 

widely observed that a field’s size “grows” throughout its lifespan. Reasons for this growth vary widely, but 

may include areal extension of existing reservoirs, discovery of new reservoirs, improvement in production 

procedures, and the natural conservatism of early estimates. A detailed discussion of reserve appreciation and 

cumulative growth factors may be found starting on page 49 of the 2000 Assessment. The estimated ultimate 

recovery volumes were then used for the forecasts in the 2000 Assessment. 
83 

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

0 100 200 300 400 500 600 700 800 900 1,000 1,100 1,200

Cumulative Number of Fields

Million Barrels Oil Equivalent

Deepwater

Shallow water

Figure 57. Modified creaming curve for shallow- and deepwater areas of the GOM 

(includes reserves, resources, and industry-announced discoveries). 

49.90

4.96

3.27

15.01

19.80

28.72

6.85

7.89

0

10

20

30

40

50

60

0-200 200-800 800-1,600 >1,600

Water-Depth Interval (m)

Billion Barrels Oil Equivalent

(grown volumes)

Total reserves

Mean resources

Figure 58. Reserves and future discovery volumes in the deepwater GOM. 
84 

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 59 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 5 shows that the most prolific blocks (on a BOE basis) are 

currently in the deepwater GOM. 

Table 5 

Top 20 Producing Blocks for the Years 2001—2002

Block Project Name Owner Water Depth (ft) Production (BOE)* 

MC 807 Mars Shell 2,933 136,568,699 

MC 809 Ursa Shell 3,800 93,241,872 

GC 200 Troika BP 2,679 67,655,971 

GB 426 Auger Shell 2,860 65,162,185 

VK 956 Ram Powell Shell 3,216 46,548,817 

GC 205 Genesis ChevronTexaco 2,590 46,305,567 

VK 786 Petronius ChevronTexaco 1,753 43,380,884 

VK 915 Marlin BP 3,236 40,218,070 

GB 260 Baldpate Amerada Hess 1,648 38,137,292 

AC 25 Hoover ExxonMobil 4,808 33,106,719 

ST 204 Unnamed El Paso 155 32,437,871 

GB 215 Conger Amerada Hess 1,500 28,898,766 

MC 687 Mensa Shell 5,280 27,248,719 

GI 116 Unnamed Anadarko 326 24,164,514 

MC 194 Cognac Shell 1,023 22,959,993 

GC 158 Brutus Shell 2,983 21,090,921 

ST 37 Unnamed ChevronTexaco 59 20,962,911 

MI 622 Unnamed BP 89 20,369,408 

VK 989 Pompano/Pompano II BP 1,290 19,584,629 

MC 899 Crosby Shell 4,259 17,819,211 

*cumulative production from January 2001 through December 2002 

Figure 60 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 23 percent of the Nation’s domestic gas 

production. A significant and growing portion of these volumes comes from the deepwater. 
85 

1996-1997

1992-1993

1994-1995

< 1,000 ft

> 1,000 ft

Leased block

(by water depth)

Figure 59. Relative volume of production from each GOM lease. Bar heights are 

proportional to total lease production (barrels of oil equivalent) during that 

interval. 
86 

1998-1999

2000-2001

2002-2003

Leased block

(by water depth)

< 1,000 ft

> 1,000 ft

Figure 59. Relative volume of production from each GOM lease. Bar heights are 

proportional to total lease production (barrels of oil equivalent) during 

that interval (continued). 
87 

Shallo wwater GOM

11%

Deepwater 

GOM

17%

Other U.S.

72% Other U.S.

77%

Shallo wwater GOM

16%

Deepwater 

GOM

7%

Figure 60. Estimated U.S. oil and gas production in 2002. 

Figure 61a 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 2002, was at its 

lowest level since 1967. The deepwater GOM oil production, however, is in the midst of a dramatic 

increase similar to that seen in the shallow-water GOM during the 1960’s. Melancon et al. (2003) 

predict that this production surge has not yet peaked. This strong increase in deepwater oil 

production more than offsets recent declines in shallow-water oil production. In 2002, deepwater oil 

production accounted for approximately 61 percent of GOM oil production. 

Figure 61b 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 steady increase in deepwater gas production that occurred in the past 

few years offsets the shallow-water decline. Appendix H lists historical GOM oil and gas production 

rates. 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 4), but the impact of the DWRRA on deepwater production is just now beginning 

to show. Figure 62a 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. The amount of oil production subject to royalty suspension 

has hovered around 5 percent of the total “deepwater” production since mid-2001. Figure 62b 

displays total “deepwater” gas production along with pre-DWRRA and post-DWRRA gas production 

subject to royalty relief. The volume of natural gas subject to DWRR increased rapidly in 2002, 

reaching 14 percent of total “deepwater” production by the end of that year. Note that pre-DWRRA 

production refers to production from leases that have been approved to receive DWRR but were 

issued before November 28, 1995. Post-DWRRA production refers to DWRR production from 

leases that were issued after that date. 

Approximately 300,000 barrels of oil and 2 billion cubic feet of gas come from deepwater subsea 

completions each day. Subsea completions currently account for about 30 percent of deepwater oil 
88 

0

200

400

600

800

1,000

1,200

1947195019531956195919621965196819711974197719801983198619891992199519982001

Year

Thousand Barrels of Oil per Day

Shallow-water oil

Deepwater oil

Figure 61a. Comparison of average annual shallow- and deepwater oil production. 

0

2

4

6

8

10

12

14

16

1947195019531956195919621965196819711974197719801983198619891992199519982001

Year

Billion Cubic Feet of Gas per Day

Shallow-water gas

Deepwater gas

Figure 61b. Comparison of average annual shallow- and deepwater gas production. 
89 

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

Month

Barrels of Oil per Day

Contribution of pre-DWRRA production

Contribution of post-DWRRA production

Total production >200 m (656 ft)

Figure 62a. 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

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02

Month

Thousand Cubic Feet per Day

Contribution of pre-DWRRA production

Contribution of post-DWRRA production

Total gas production >200 m (656 ft)

Figure 62b. Contribution of DWRRA gas production to total gas production in water depths 

greater than 200 m (656 ft). 
90 

production and about 50 percent of deepwater gas production. Figure 63a 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 they accounted for over 40 percent of 

deepwater GOM gas production (Figure 63b). Gas production from subsea completions increased 

from 1996 through 1999, remained constant in 2000, and increased rapidly after 2000. 

COMPANIES AND PRODUCTION

Deepwater oil and gas production was confined almost entirely to major oil and gas companies 

through 1996 (figures 64a-b). (Production volumes in figures 64a-b, 65a-b, and 66a-b are attributed 

to companies on the basis of their percentage of lease ownership. For example, if Shell owned 

75 percent of a particular lease in July 1997, then 75 percent of that lease’s production was attributed 

to Shell that month.) In 1998 and 1999, nonmajor companies significantly increased their deepwater 

oil production (figure 64a). However, since 2000, nonmajor oil production has leveled off while 

major oil companies continued their steep increases in oil production. Gas production from 

nonmajor and major companies has increased at approximately the same rate (figure 64b). Nonmajor 

companies currently own about 25 percent of deepwater GOM oil production and 30 percent of gas 

production. 

In shallow water, nonmajor companies now produce more oil than the majors (figure 65a). In 

addition, nonmajor gas production represents an increasingly greater share of the total shallow-water 

gas production (figure 65b). This confirms the speculation that majors have been concentrating more 

in deepwater for their production needs. 

Figures 66a and 66b display production contributions from each major oil and gas company. Shell 

and BP were the driving forces behind increasing deepwater production, with Shell as the clear 

leader in both oil and gas production. Shell’s dominance in deepwater oil production began before 

1992 and its recent increases have outpaced those of the other major companies. Shell also led in 

deepwater gas production, including a dramatic increase in 1997. BP oil production increased 

significantly since 1998 (in part because Shell and BP have joint ownership in several large 

deepwater fields). BP is second in terms of gas production because of steep increases in deepwater 

gas production since the last report. Note that BP has several significant projects on the horizon 

(e.g., Mad Dog, Thunder Horse, and Atlantis) that will contribute significantly to its oil and gas 

production totals. 

PRODUCTION RATES

High well production rates have been a driving force behind the success of deepwater operations. 

Figure 67a 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 on line in early 2002 in 5,400 ft (1,646 m) water depth with a single well maximum rate of 

more than 30,000 BOPD. The deepest production is currently held by Camden Hills in 7,216 ft 

(2,199 m) water depth. 

Figure 67b 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. The record daily oil and gas production 

rates (for a single well) are 41,532 BOPD (Troika) and 145 MMCFPD (Mica). 
91 

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

Month

Barrels of Oil per Day

Subsea oil

Total deepwater oil

Figure 63a. 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

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02

Month

Thousand Cubic Feet of Gas per Day

Subsea gas

Total deepwater gas

Figure 63b. Contributions from subsea completions toward total deepwater gas production. 
92 

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02

Month

Barrels of Oil per Day

Majors

Nonmajors

Figure 64a. Comparison of major and nonmajor companies in terms of deepwater oil production. 

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

8,000,000

9,000,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02

Month

Thousand Cubic Feet per Day

Majors

Nonmajors

Figure 64b. Comparison of major and nonmajor companies in terms of deepwater gas 

production. 
93 

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02

Month

Barrels of Oil per Day

Majors

Nonmajors

Figure 65a. Comparison of major and nonmajor companies in terms of shallow-water oil 

production. 

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

8,000,000

9,000,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02

Month

Thousand Cubic feet per Day

Majors

Nonmajors

Figure 65b. Comparison of major and nonmajor companies in terms of shallow-water gas 

production. 
94 

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02

Month

Barrels of Oil per Day

BP

ChevronTexaco

ExxonMobil

Shell

Figure 66a. Contributions from each major oil company toward total deepwater oil production. 

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02

Month

Thousand Cubic Feet of Gas per Day

BP

ChevronTexaco

ExxonMobil

Shell

Figure 66b. Contributions from each major oil company toward total deepwater gas production. 
95 

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

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 5,000-7,499 ft

Bullwinkle Auger

Mars

Troika

Ursa Brutus

Horn Mountain

Figure 67a. 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

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02

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 5,000-7,499 ft 

Bullwinkle

Mensa 

Popeye

Popeye

Diamond

Mica

Figure 67b. Maximum production rates for a single well within each water-depth category for 

deepwater gas production. 
96 

Figure 68a shows that the average deepwater oil completion currently produces at 20 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 8 times the rate of the average shallow-water gas completion 

(figure 68b). 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 69a-b. First, average oil and gas production rates per well 

are increasing and, secondly, production rates are declining from their peaks more rapidly in recent 

years. These figures plot monthly average oil and gas production rates for all wells completed in a 

specific year. For example, in figure 69a, the 1992 line represents oil well production for oil wells 

completed in 1992 divided by the number of oil wells completed in that year. The 1992 line tracks 

production from these completions in successive years. 

Figures 70a (oil) and 70b (gas) compare maximum historical production rates for each lease in the 

GOM, i.e., the well with the highest historical 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 70a also shows that maximum oil rates were significantly higher off the southeast Louisiana 

coast than off the Texas coast. Figure 70b 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). 
97 

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

Month

Barrels of Oil per Day

Shallow water

Deepwater

Figure 68a. 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

Month

Thousand Cubic Feet of Gas per Day

Shallow water

Deepwater

Figure 68b. Average production rates for shallow-water and deepwater gas well completions. 
98 

0

50

100

150

200

250

300

350

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02

Month

 Average Daily Oil Production MBOPD

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

19

30

88

32

176

199

261 263

287

127

Figure 69a. Deepwater oil production profiles (oil wells coming onstream between 1992 and 

2002). 

0

100

200

300

400

500

600

700

800

900

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02

Month

 Average Daily Gas Production MMCFPD

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

43

193

295

368

340

590

525

652

707

Figure 69b. Deepwater gas production profiles (gas wells coming onstream between 1992 and 

2002).
99

Mississippi 

Louisiana

Texas

1000 ft 1500 ft

5000 ft

7500 ft

Mississippi 

Louisiana

Texas

16,000

8,0003,000

37,000

Maximum Oil Rate

(barrels per day)

Auger

SS182

Troika

Genesis

Ursa

Europa Mars

Ram Powell Hoover Diana

Figure 70a. Maximum historical oil production rates for Gulf of Mexico wells. 
100

Mississippi

Louisiana

Texas

1000 ft 1500 ft

5000 ft

7500 ft

Mississippi

Louisiana

Texas

160,000120,000

80,00040,000

200,000

Maximum Gas Rate

(MCF per day)

EC334

WC580

SM40

SS239

MO823

MO869

Auger

Popeye Mars

Figure 70b. Maximum historical gas production rates for Gulf of Mexico wells. 
101 

SUMMARY AND CONCLUSIONS 

This report has discussed 

• significant new discoveries that open large new geologic plays; 

• technological innovations and new concepts (e.g., hydrate potential, impact of loop 

currents, and LNG terminals) that may have significant effects on the energy outlook of 

the GOM; 

• sustained deepwater leasing activity and stabilized average bid amounts per block; 

• 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 ultra-deep 

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; 

• predictions for future large deepwater field discoveries; 

• the increasing contribution of deepwater oil and gas production toward total GOM 

production; 

• the domination by major oil companies in deepwater production, led by Shell and BP; 

and 

• the production rates of deepwater wells exceeding those of shallow-water wells by 800 

to 2,000 percent. 

The remainder of this report combines historical leasing, drilling, development, reserve, and production 

data, revealing overall trends in deepwater activity and expectations. 

Figure 71 illustrates deepwater projects that began production in 2003 and those expected to commence 

production in the next 4 years. Twelve deepwater projects began production in 2003, another 13 are 

expected to begin in 2004, and many more are expected in the following years. In addition to the projects 

shown in figure 71, 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 72). (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 2005. 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, 
102

#S $

#S $ #S #S#S #S #S 

#S $$ $ $

#S $ #S$ $

#S $ $ $ $ $ #S $ $ $ $$ $ $

7500 ft

5000 ft

1500 ft 1000 ft

Louisiana Mississippi Ala

Texas

Falcon

Gunnison

Habanero Boris

Matterhorn

Pardner

H

E

Zia

Medusa

Goose

Raptor

Tomahawk

Llano

Entrada

Magnolia

Red Hawk

Glider

Front Runner

Marco Polo

Atlantis

Holstein Mad Dog

Constitution Tahiti

Rigel 

Triton

Devil's Tower

Thu

K

Balboa

Online 2003Online 2004-2007

S#

$

Figure 71. Deepwater projects that began production in 2003 and those expected to begin production by yearend 200
103

30

223

539

863

405

2,075

696

32

1,002

395

332

102

4 11 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-

Year Lease Sale

Number of Leases

Number of leasesAverage U.S. oil priceAverage U.S. natural gas price (w

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 72. Deepwater lease activity and oil/natural gas prices (prices from U.S. Energy Information Administ

September 2003 and natural gas through July 2003). 
104 

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 project in 2001. Similarly, acreage at Constitution was acquired in 2001, 

the first well was drilled that same year, and production is expected to begin 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 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 time period from lease acquisition to first production; however, this interval has 

decreased from 10 to less than 7 years. Figures 73a-c demonstrate average lags associated with 

deepwater operations. These figures use data from only productive deepwater leases. Figure 73a shows 

the average number of years it took to drill a well from the time the lease was issued. Figure 73b shows 

the average length of time from lease issue to qualification1

 of the lease as productive. Figure 73c 

illustrates the lags between leasing, qualification, and first production. 

There are two lags represented in figures 73a-c. First, there is a lag between a deepwater discovery and 

the operator’s request for lease qualification. Operators sometimes announce discoveries to the public 

long before qualifying the lease as productive with MMS (and thereby being granted field status). The 

second lag depicted in figures 73a-c is the lag between leasing and subsequent operations (drilling, 

qualifying, and production). Note that, since deepwater leases are in effect for 8 or 10 years, the data are 

incomplete beyond 1993. The apparent decreasing lags for leases issued after 1993 are explained by the 

fact that the lease evaluation process has not yet been completed. 

The data show an increase from 1976 to 1987 in the number of years before the first well is drilled 

(figure 73a). 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 

areawide 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 of the first well and qualifying 

the lease (figure 73b). During most of the 1980’s, it took 10-11 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 throughout the 1980’s. That is, operators brought fields 

online in about 10 years, despite the fact that the first wells were not drilled, on average, until about the 

fourth year of the lease term by the late 1980’s. The most recent complete data (many leases issued after 

1993 are still in their primary terms) indicate that the time from lease to first production has decreased 

from over 10 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 74. For any given lease-sale year, almost 50 percent of tested 

leases were first drilled within three years of lease acquisition, and 23 percent were drilled in year eight or 

later. Twenty-nine percent of the hydrocarbon volumes were discovered during the first three years of 

their lease terms, but 44 percent of the hydrocarbon volumes were discovered in year eight or later. The 

 

1

 An operator may request a “Determination of Well Producibility” from MMS. A successful MMS determination 

then “qualifies” the lease as producible. Not all qualified leases ultimately begin production. 
105 

2.47 2.07

4.69 5.28

6.69 5.82 4.76

3.30 2.64 2.57 1.67

5.00

0.00 1.00 0.00 0

2

4

6

8

10

12

14

1974 -75 1978 -79 1982 -8 3 1986 -8 7 199 0-91 19 94-95 199 8-9 9 200 2-03

Year Lease Acquired

Number of Years

Years to first well

leases in primary term

Figure 73a. Lag from leasing to first well for producing deepwater fields. 

1.53

3.00

3.50

1.00

1.77

1.98

4.00

1.91

1.18

1.70

1.00 0.86

1.00

0.20

1.00

0

2

4

6

8

10

12

14

19 74 -75 19 78 -79 19 8 2 -8 3 19 8 6 -8 7 19 90 -91 19 94 -95 19 98 -99 2 00 2 -0 3

Year Lease Acquired

Number of Years

Additional time to qualify

Years to first well

leases in p rimary term

Figure 73b. Lag from leasing to qualifying for producing deepwater fields. 

6.00

4.00

2.50 8.40

5.50 4.22

3.00

2.82

1.82

1.70

1.27 0.90 1.11

1.00

0.00

0

2

4

6

8

10

12

14

16

1974-75 1978-79 19 82-83 19 86-87 199 0-9 1 1994 -95 1998 -99 200 2-03

Year Lease Acquired

Number of Years

Additional time to first production 

Additional time to qualify

Years to first well

leases in primary term

Figure 73c. Lag from leasing to first production for producing deepwater fields. 
106

30

13

10

9

8

4 3 3

1 2

1 

4

10

0

200400600800

1,0001,2001,4001,600

Year of Lease Term

Million BOE Discovered

Reserves & resources Percent wells drilled 

Reserves & resources 1096.431 1033.227 713.1991 402.4035 1339.217 672.2695 281.9353 143.1564 342.3876 627.8707 1515.078 25.83244 1457.957 2Percent wells drilled 30 10 9 8 13 4 3 3 4 10 1 2 1 

1 2 3 4 5 6 7 8 9 10 11 12 13 

includes N. Thunder Horse

includes Thunder Horse & Mad Dog

includes Mars

includes Auge

r

Figure 74. Year in the lease term in which BOE was discovered and percent of leases were tested, for deepwater leas
107 

data for this analysis include only deepwater leases acquired through 1994, 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, and the majority 

of hydrocarbons are also found during the same period. What is surprising is the amount of major 

discoveries found in the later years of some leases’ terms. Certainly, the discoveries of Thunder Horse, 

North Thunder Horse, and Mad Dog, occurring late in their lease terms, have greatly impacted these 

volume totals. This demonstrates the difficulty in recognizing the best prospects at the beginning of a 

lease’s term. 

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 will remain untested when their terms expire. Figure 75 shows 

historical lease activity trends. As mentioned previously, these data are complete only through 1993, 

since most deepwater leases beyond that time are still under their primary terms and still under 

evaluation. Similar to today’s large lease inventory is the period from 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. 

Figures 76a-b show that the reduction in drilling (figure 33) is not related to a lack of success in finding 

hydrocarbons. Exploratory drilling is arguably the most important indicator of exploration effort. 

Figures 76a-b use 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 76a. 

The amount discovered includes reserves, resources, and industry-announced discoveries (same data as 

figure 56). Notice that, in the last two years there has been a decline in the number of new leases tested 

and in the amount of hydrocarbons discovered. Much of the drop in the amount discovered is caused by 

the 24-month delay in industry’s release of proprietary drilling results. Volumes in 2002 and 2003 are, 

therefore, significantly understated. 

Figure 76b shows the average volume of hydrocarbons added for a tested lease. Although the scatter of 

data points is wide, the trend shows an increasing volume discovered per lease drilled. The figure shows 

that there is no decline in exploration rewards in the deepwater GOM. With the addition of complete 

discovery results for years 2002 and 2003, the trend will continue to increase. 

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 77a-c. There is only a general correlation between the number of leases issued and those drilled 

and produced (figures 77a-b). In contrast, the number of deepwater leases drilled correlates strongly with 

the number of those leases that later produced (figure 77c). 

Figure 78 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 2003 are in 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 2000 is very evident and 

propagates through to 2010. Future values for primary term leases, lease expirations, and leases drilled 

are in the dotted lines. These values assume that, after the year 2004, 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 3,200 deepwater leases 

issued from 1996 through 2000, however, only 6.5 percent have been drilled to date. There are over 

2,400 leases from these sales still in their primary lease term, with more than 750 of these leases in water 

depths of greater than 7,000 ft (2,134 m). Only 34 wells have been drilled on the ultra-deepwater leases 
108

395

1,002

696

2,075

863

405

539

223

32

11 4 30

332

102

0%

10%20%30%40%50%60%70%80%90%

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 2000-0

Year Lease Sale

Percent of Leases with Activity

Percent leases drilledPercent leases productiveNumber of leases acquired

leases in primary term

Figure 75. Activity on deepwater leases. 
109 

0

10

20

30

40

50

60

70

80

197419761978198019821984198619881990199219941996199820002002

Year

Number of Leases Drilled

0

500

1000

1500

2000

2500

Millions of BOE Discovered 

Number of leases drilled

Total deepwater MMBOE discovered

Figure 76a. Leases drilled and barrels found. 

0

10

20

30

40

50

60

70

197419761978198019821984198619881990199219941996199820002002

Year

Million Barrels of Oil Equivalent

low estimates

Figure 76b. Exploration effort and reward: number of leases drilled in a year and BOE 

discovered per lease. 
110 

0

200

400

600

0 20 40 60 80 100

Number of Leases Drilled

Number of Leases Issued

Figure 77a. Relationship between number of leases issued and 

number of leases drilled, 1974-1993. 

0

200

400

600

0 5 10 15 20 25

Number of Producing Leases

Number of Leases Issued

Figure 77b. Relationship between number of leases issued and 

number of resulting producing leases, 1974-1993. 

0

50

100

0 5 10 15 20 25

Number of Producing Leases

Number of Leases Drilled

Figure 77c. Relationship between number of leases drilled and 

number of resulting producing leases, 1974-1993. 
111 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

1985198619871988198919901991199219931994199519961997199819992000200120022003200420052006200720082009201020112012

Year

Number of Leases

Leases tested 

Leases expiring

Untested leases in primary term

Figure 78. The challenge of deepwater lease evaluation. 

from these sales, 11 of these wells resulted in announced discoveries. Figure 78 shows 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. 

EXPANDING FRONTIER

It is instructive to look back to the earlier deepwater reports (figure 79) 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 last report, Thunder 

Horse was in the discovered-volumes category, and in this report its volumes are classified as proved 

reserves. While both proved reserves and discovered volumes have substantially increased from report to 

report, the most dramatic increases have occurred in the discovered volumes. This suggests 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 78, 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. As shown in figure 57, the immature deepwater creaming curve predicts that 

numerous large undiscovered fields remain. The 2000 Assessment indicates that more than 50 billion 

recoverable BOE remain to be discovered (Lore et al., 2001). 
112 

8,622

12,781

15,573

4,015 4,385

6,702

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

Million Barrels of Oil Equivalent

2000 2002 2004

Year of Report

Proved Reserves

Proved and Unproved Reserves + Resources + Industry-Announced

Discoveries

Figure 79. Comparison of 2000, 2002, and 2004 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 (Baud et al., 2002) documented the advancements made in 

deepwater exploration and development since 1974. Several notable changes have occurred in the 

deepwater GOM since the last report. 

• The deepwater frontier is now in water depths greater than 7,000 ft (2,134 m). 

• The first exploratory well was drilled in over 10,000-ft (3,048-m) water depth. 

• The first deepwater well was drilled below 30,000-ft (9,144-m) depth (true vertical 

depth). 

• Eleven discoveries were found in over 7,000-ft (2,134-m) water depths. 

• The deepest production increased from approximately 5,300-ft (1,615-m) water depth 

(Mensa) to over 7,000-ft (2,134-m) water depth (Camden Hills). 

• The first deepwater discoveries in the Eastern GOM were found. 

• There were significant new discoveries in both Walker Ridge and Alaminos Canyon in 

older, lightly tested Paleogene reservoirs. 

• Industry has made great technological achievements (e.g., polyester mooring, composite 

riser, cell spars, and 15,000-psi subsea trees). 

• Loop currents have been recognized as posing significant design challenges for 

deepwater structures, rigs, and pipelines. 

• The average number of operating rigs is down 29 percent and the number of wells drilled 

is down 37 percent. 

• Average bid amounts per block have stabilized or decreased slightly. 

• There was a 51 percent increase in the number of producing deepwater projects. 
113 

• Nonmajor companies have made more deepwater discoveries and hold more deepwater 

acreage than the major companies. 

• Deepwater production rose more than 100 MBOPD and 400 MMCFPD each year since 

1997. 

• Subsea gas production has increased 90 percent since December 2000. 

Since the start of 2000, new deepwater drilling added over 4.5 billion BOE, a 40 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 are all indicators of the expanding frontier. This 

ensures that the deepwater GOM will remain as one of the world’s premier oil and gas basins. 

115 

CONTRIBUTING PERSONNEL 

This report includes contributions from the following individuals. 

Pat Adkins 

Kim Altobelli 

Roy Bongiovanni 

Pat Bryars 

Mike Dorner 

Jim Grant 

Fred Jacobs 

Bill Lang 

Debbie Miller 

Paul Post 

Mike Prendergast 

Terry Rankin 

Mike Smith 

Warren Williamson 

117 

REFERENCES 

Bascle, B. J., L. D. Nixon and K. M. Ross, 2001, Atlas of Gulf of Mexico Gas and Oil Reservoirs as of 

January 1, 1999. Minerals Management Service, Gulf of Mexico OCS Region. OCS Report MMS 

2001-086, CD-ROM.

Baud, R. D., R. H. Peterson, G. E. Richardson, L. S. French, J. Regg, T. Montgomery, T. Scott Williams, 

C. Doyle, and M. Dorner, 2002, Deepwater Gulf of Mexico 2002: America’s Expanding Frontier. 

Minerals Management Service, Gulf of Mexico OCS Region. OCS Report MMS 2002-021. New 

Orleans. 133 p. 

Cranswick, D., and J. Regg, 1997, Deepwater in the Gulf of Mexico: America’s New Frontier. Minerals 

Management Service, Gulf of Mexico OCS Region. OCS Report MMS 97-0004. New Orleans. 

41 p. 

Crawford, T. G., G. L. Burgess, C. J. Kinler, M. T. Prendergast, and K. M. Ross, 2003, Estimated Oil and 

Gas Reserves, Gulf of Mexico Outer Continental Shelf, December 31, 2000. Minerals Management 

Service, Gulf of Mexico OCS Region. OCS Report MMS 2003-050. New Orleans. 26 p. 

Hamilton, P., J. J. Singer, E. Waddell, and K. Donohue, 2003, Deepwater Observations in the Northern 

Gulf of Mexico from In-Situ Current Meters and PIES, Volume II: Technical Report. Minerals 

Management Service, Gulf of Mexico OCS Region. OCS Report MMS 2003-049. New Orleans. 

95 p. 

Harding, B. W., and E. K. Albaugh, 2003, “2003 Worldwide Survey of Deepwater Drilling Rigs.” 

Offshore, July 2003. 

Lore, G. L., D. A. Marin, E. C. Batchelder, W. C. Courtwright, R. P. Desselles, Jr. and R. J. Klazynski, 

2001, 2000 Assessment of Conventionally Recoverable Hydrocarbon Resources of the Gulf of Mexico 

and Atlantic Outer Continental Shelf as of January 1, 1999. Minerals Management Service, Gulf of 

Mexico OCS Region. OCS Report MMS 2001-087. New Orleans. 652 p. (CD—ROM only). 

Melancon, J. M., R. Bongiovanni, and R. D. Baud, 2003, Gulf of Mexico Outer Continental Shelf Daily 

Oil and Gas Production Rate Projections From 2003 Through 2007. Minerals Management Service, 

Gulf of Mexico OCS Region. OCS Report MMS 2003-028. New Orleans. 17p. 

Monthly Energy Review, October 2003. Energy Information Administration, Office of Energy Markets 

and End Use, U.S. Department of Energy. www.eia.doe/emeu/aer/txt/tab0516.htm. 

Shirley, K., 2001, “Time is Proving the Value of 4D.” AAPG Explorer. Vol. 22. No. 9. 

U.S. Dept. of the Interior, Minerals Management Service. 2000. Gulf of Mexico Deepwater Operations 

and Activities: Environmental Assessment. U.S. Dept. of the Interior, Minerals Management Service, 

Gulf of Mexico OCS Region, New Orleans, LA. OCS EIS/EA MMS 2000-001. 

119 

APPENDICES 

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

Project Name Area/Block 

Water 

Depth 

(ft)1 Field 

Field 

Discovery 

Date2

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 

Angus GC 112 2,045 GC 112 6/08/1997 1999 

Ariel/Na Kika MC 429 6,240 MC 429 11/20/1995 

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 GC 699 5/12/1998 

Atlas LL 50 8,934 

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 7/2/2001 

Baldpate GB 260 1,648 GB 260 11/01/1991 1998 

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 EB 643 3,650 EB 643 12/13/1997 2002 

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 8/4/1999 2002 

Cascade WR 206 8,143 

Champlain AT 63 4,457 AT 063 2/11/2000 

Chinook WR 469 8,831 

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 

Cooper GB 388 2,600 GB 388 3/16/1989 1995 1999 

Coulomb/Na Kika MC 657 7,591 MC 657 11/01/1987 

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 
120 

Project Name Area/Block 

Water 

Depth 

(ft)1 Field 

Field 

Discovery 

Date2

Year of 

First 

Production 

Year of 

Last 

Production 

Devil's Tower MC 773 5,610 MC 773 12/13/1999 

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 

Dionysis 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 

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 3870 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 339 3,330 GC 339 6/08/2001 

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 147 GC 147 1,275 GC 147 5/01/1988 

GC 162 GC 162 2,616 GC 162 7/01/1989 

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 

Glider GC 248 3,440 

Gomez MC 755 3,098 MC 755 3/19/1986 
121 

Project Name Area/Block 

Water 

Depth 

(ft)1 Field 

Field 

Discovery 

Date2

Year of 

First 

Production 

Year of 

Last 

Production 

Goose MC 751 1,624 MC 751 12/15/2002 2003 

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 

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 644 4,344 GC 644 2/11/1999 

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 

Jolliet GC 184 1,760 GC 184 7/01/1981 1989 

Jubilee AT 349 8,825 

K2 GC 562 4,006 GC 562 8/14/1999 

Kepler/Na Kika MC 383 5,759 

King (MC-BP) MC 84 5,000 MC 084 1/01/1993 2002 

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 

Ladybug GB 409 1,355 GB 409 5/13/1997 2001 

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 

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 

Madison AC 24 4,856 AC 024 6/25/1998 2002 

Magnolia GB 783 4,674 GB 783 5/03/1999 

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 

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 
122 

Project Name Area/Block 

Water 

Depth 

(ft)1 Field 

Field 

Discovery 

Date2

Year of 

First 

Production 

Year of 

Last 

Production 

MC 113 MC 113 1,986 MC 113 1/01/1976 

MC 285 MC 285 3,161 MC 285 9/01/1987 

MC 29 MC 29 2,266 MC 029 3/04/1998 

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 

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 

Moccasin GB 254 1,920 GB 254 7/23/1993 

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 10/01/1968 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 
123 

Project Name Area/Block 

Water 

Depth 

(ft)1 Field 

Field 

Discovery 

Date2

Year of 

First 

Production 

Year of 

Last 

Production 

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 

Poseiden (GC) GC 691 4,489 GC 691 2/27/1996 

Poseiden (MC) MC 772 5,567 MC 728 6/30/2002 

Prince EW 1003 1,500 EW 958 7/20/1994 2001 

Princess MC 765 3,600 MC 807 4/01/1989 2002 

Prosperity VK 742 1,004 VK 742 8/08/1997 

Ptolemy GB 412 1,322 GB 412 7/01/1984 

Puma GC 823 4,129 

Ram-Powell VK 956 3,216 VK 956 5/01/1985 1997 

Raptor EB 668 3,710 EB 668 9/13/2003 

Red Hawk GB 877 5,334 GB 877 10/18/2001 

Rigel MC 252 5,225 MC 252 11/29/1999 

Rockefeller EB 992 4,872 EB 992 11/28/1995 

Rocky GC 110 1,785 GC 110 8/07/1987 1996 

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 

Shasta GC 136 1,048 GC 136 7/01/1981 1995 

Shenzi GC 653 4,238 

Spiderman DC 621 8,087 

St. Malo WR 678 7,036 

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 

Tahiti GC 640 4,292 

Tahoe VK 783 1,500 VK 783 12/01/1984 1994 

Thunder Horse MC 778 6,050 MC 778 4/01/1999 

Thunder Horse 

North MC 776 5,660 

Timberwolf MC 555 4,749 MC 555 10/30/2001 

Tomahawk EB 759 4,114 EB 759 1/28/2003 

Trident AC 903 9,743 

Triton MC 728 5,373 MC 728 6/30/2002 

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 
124 

Project Name Area/Block 

Water 

Depth 

(ft)1 Field 

Field 

Discovery 

Date2

Year of 

First 

Production 

Year of 

Last 

Production 

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 

VK 962 VK 962 4,677 VK 962 11/15/2001 

Vortex AT 261 8,344 

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

 Water depths shown reflect depth at facility. If project is subsea or undeveloped, water depth reflects depth of deepest well 

location in project. 2

 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. 
125 

Appendix B. Announced Deepwater Discoveries (Sorted by Discovery Date).

Project Name Area/Block 

Water 

Depth 

(ft)1 Field 

Field 

Discovery 

Date2

Year of 

First 

Production 

Year of 

Last 

Production 

Pardner MC 401 1,139 WD 152 10/01/1968 2003 

Cognac MC 194 1,023 MC 194 7/01/1975 1979 

MC 68 MC 68 1,360 MC 068 12/09/1975 2001 

MC 113 MC 113 1,986 MC 113 1/01/1976 

Lena MC 280 1,000 MC 281 5/01/1976 1984 

VK 862 VK 862 1,043 VK 862 10/01/1976 1995 

Zinc MC 354 1,478 MC 354 8/01/1977 1993 

Pompano VK 990 1,290 VK 990 5/01/1981 1994 

Jolliet GC 184 1,760 GC 184 7/01/1981 1989 

Shasta GC 136 1,048 GC 136 7/01/1981 1995 

Dionysis VK 864 1,508 VK 864 10/01/1981 

Alabaster MC 485 1,438 MC 397 8/27/1982 1992 

Bullwinkle GC 65 1,353 GC 065 10/01/1983 1989 

Amberjack MC 109 1,100 MC 109 11/13/1983 1991 

GC 29 GC 29 1,554 GC 029 1/01/1984 1988 1990 

GC 39 GC 39 2,068 GC 039 4/01/1984 

Marathon GC 153 1,618 GC 153 4/01/1984 

GC 70 GC 70 1,618 GC 070 6/01/1984 

Ptolemy GB 412 1,322 GB 412 7/01/1984 

El Toro GC 69 1,465 GC 069 9/13/1984 

GC 21 GC 21 1,296 GC 021 10/01/1984 

Typhoon GC 237 2,679 GC 236 10/01/1984 2001 

Tahoe VK 783 1,500 VK 783 12/01/1984 1994 

Allegheny GC 254 3,294 GC 254 1/01/1985 1999 

Popeye GC 116 2,000 GC 116 2/01/1985 1996 

GC 31 GC 31 2,243 GC 075 5/01/1985 1988 1989 

Ram-Powell VK 956 3,216 VK 956 5/01/1985 1997 

GB 379 GB 379 2,076 GB 379 7/01/1985 

GC 228 GC 228 1,950 GC 228 7/01/1985 

EB 377 EB 377 2,450 EB 377 10/01/1985 

Oyster EW 917 1,195 EW 873 12/01/1985 1998 

Leo MC 546 2,505 MC 546 2/01/1986 

MC 455 MC 455 1,400 MC 455 2/01/1986 

Bison GC 166 2,381 GC 166 3/01/1986 

Gomez MC 755 3,098 MC 755 3/19/1986 

Black Widow EW 966 1,850 EW 921 5/01/1986 2000 
126 

Project Name Area/Block 

Water 

Depth 

(ft)1 Field 

Field 

Discovery 

Date2

Year of 

First 

Production 

Year of 

Last 

Production 

Morpeth EW 921 1,696 EW 921 5/01/1986 1998 

Mensa MC 731 5,318 MC 731 12/01/1986 1997 

MC 709 MC 709 2,599 MC 709 2/01/1987 

Auger GB 426 2,860 GB 426 5/01/1987 1994 

Manatee GC 155 1,939 GC 110 8/07/1987 2002 

Rocky GC 110 1,785 GC 110 8/07/1987 1996 

MC 285 MC 285 3,161 MC 285 9/01/1987 

Coulomb/Na Kika MC 657 7,591 MC 657 11/01/1987 

MC 929 MC 929 2,250 MC 929 11/01/1987 

Neptune 

(VK-Kerr McGee) VK 826 1,930 VK, 825 11/01/1987 1997 

EW 1006 EW 1006 1,884 EW 1006 1/26/1988 1999 

Einset VK 872 3,500 VK 873 3/01/1988 2001 

GC 147 GC 147 1,275 GC 147 5/01/1988 

Genesis GC 205 2,590 GC 205 9/01/1988 1999 

King Kong GC 472 3,980 GC 472 2/01/1989 2002 

Yosemite GC 516 4,150 GC 472 2/01/1989 2002 

Brutus GC 158 3,300 GC 158 3/01/1989 2001 

Cooper GB 388 2,600 GB 388 3/16/1989 1995 1999 

King (MC-Shell) MC 764 3,250 MC 807 4/01/1989 2000 

Mars MC 807 2,933 MC 807 4/01/1989 1996 

Princess MC 765 3,600 MC 807 4/01/1989 2002 

Ursa MC 809 3,800 MC 807 4/01/1989 1999 

Fourier/Na Kika MC 522 6,950 MC 522 7/01/1989 2003 

GC 162 GC 162 2,616 GC 162 7/01/1989 

GC 27 GC 27 1,593 GC 027 7/01/1989 

Herschel/Na Kika MC 520 6,739 MC 522 7/01/1989 2003 

Mica MC 211 4,580 MC 211 5/01/1990 2001 

Diana EB 945 4,500 EB 945 8/01/1990 2000 

Matterhorn MC 243 2,850 MC 243 9/01/1990 2003 

GB 302 GB 302 2,411 GB 302 2/01/1991 

GB 208 GB 208 1,275 GB 208 9/01/1991 

Baldpate GB 260 1,648 GB 260 11/01/1991 1998 

Conger GB 215 1,500 GB 260 11/01/1991 2000 

Penn State GB 216 1,450 GB 260 11/01/1991 1999 

Diamond MC 445 2,095 MC 445 12/05/1992 1993 1999 

Horn Mountain MC 127 5,400 MC 084 1/01/1993 2002 

King (MC-BP) MC 84 5,000 MC 084 1/01/1993 2002 
127 

Project Name Area/Block 

Water 

Depth 

(ft)1 Field 

Field 

Discovery 

Date2

Year of 

First 

Production 

Year of 

Last 

Production 

Virgo VK 823 1,130 VK 823 1/01/1993 1999 

King's Peak DC 133 6,845 DC 133 3/01/1993 2002 

Marlin VK 915 3,236 VK 915 6/01/1993 2000 

Moccasin GB 254 1,920 GB 254 7/23/1993 

Europa MC 935 3,870 MC 935 4/22/1994 2000 

Supertramp MC 26 1,272 MC 026 5/27/1994 

Troika GC 244 2,721 GC 244 5/30/1994 1997 

Prince EW 1003 1,500 EW 958 7/20/1994 2001 

Habanero GB 341 2,015 GB 387 10/03/1994 2003 

Llano GB 386 2,663 GB 387 10/03/1994 

Nirvana MC 162 3,724 MC 162 11/30/1994 

Fuji GC 506 4,262 GC 506 1/30/1995 

Petronius VK 786 1,753 VK 786 7/14/1995 2000 

Gemini MC 292 3,393 MC 292 9/07/1995 1999 

Neptune 

(AT-BHP) AT 575 6,220 AT 575 9/26/1995 

Pluto MC 674 2,828 MC 718 10/20/1995 1999 

Ariel/Na Kika MC 429 6,240 MC 429 11/20/1995 

Rockefeller EB 992 4,872 EB 992 11/28/1995 

Macaroni GB 602 3,600 GB 602 1/21/1996 1999 

Poseiden (GC) GC 691 4,489 GC 691 2/27/1996 

Mosquito Hawk GB 269 1,102 GB 269 3/06/1996 

PI 525 PI 525 3,430 PI 525 4/30/1996 

Baha AC 600 7,620 AC 600 5/23/1996 

Arnold EW 963 1,800 EW 963 6/12/1996 1998 

Serrano GB 516 3,153 GB 516 7/23/1996 2001 

Hoover AC 25 4,825 AC 025 1/30/1997 2000 

Diana South AC 65 4,852 AC 065 3/24/1997 

Cyclops AT 8 3,135 AT 008 4/26/1997 

Nile VK 914 3,535 VK 914 4/30/1997 2001 

Ladybug GB 409 1,355 GB 409 5/13/1997 2001 

Angus GC 112 2,045 GC 112 6/08/1997 1999 

Prosperity VK 742 1,004 VK 742 8/08/1997 

East Anstey/ 

Na Kika MC 607 6,590 MC 607 11/12/1997 2003 

Boomvang EB 643 3,650 EB 643 12/13/1997 2002 

Crosby MC 899 4,400 MC 899 1/04/1998 2001 

Mirage MC 941 3,927 MC 899 1/04/1998 
128 

Project Name Area/Block 

Water 

Depth 

(ft)1 Field 

Field 

Discovery 

Date2

Year of 

First 

Production 

Year of 

Last 

Production 

Morgus MC 942 3,960 MC 899 1/04/1998 

Dulcimer GB 367 1,120 GB 367 2/09/1998 1999 

MC 29 MC 29 2,266 MC 029 3/04/1998 

Atlantis GC 699 6,133 GC 699 5/12/1998 

Northwestern GB 200 1,736 GB 200 5/14/1998 2000 

Tulane GB 158 1,054 GB 200 5/14/1998 2002 

Madison AC 24 4,856 AC 024 6/25/1998 2002 

McKinley GC 416 4,019 GC 416 7/14/1998 

Marshall EB 949 4,376 EB 949 7/30/1998 2001 

Medusa MC 582 2,223 MC 582 10/10/1998 2003 

Medusa North MC 538 2,223 MC 582 10/10/1998 

Zia MC 496 1,804 MC 582 10/10/1998 2003 

Mad Dog GC 782 4,428 GC 826 11/24/1998 

GC 463 GC 463 4,032 GC 463 12/01/1998 

Holstein GC 644 4,344 GC 644 2/11/1999 

Aconcagua MC 305 7,100 MC 305 2/21/1999 2002 

Oregano GB 559 3,400 GB 559 3/27/1999 2001 

Thunder Horse MC 778 6,050 MC 778 4/01/1999 

Magnolia GB 783 4,674 GB 783 5/03/1999 

Camden Hills MC 348 7,216 MC 348 8/04/1999 2002 

K2 GC 562 4,006 GC 562 8/14/1999 

Sangria GC 177 1,487 GC 177 8/22/1999 2002 

Nansen EB 602 3,675 EB 602 9/25/1999 2002 

Navajo EB 690 4,210 EB 602 9/25/1999 2002 

Rigel MC 252 5,225 MC 252 11/29/1999 

Devil's Tower MC 773 5,610 MC 773 12/13/1999 

Gretchen GC 114 2,685 GC 114 12/18/1999 

Champlain AT 63 4,457 AT 063 2/11/2000 

Marco Polo GC 608 4,320 GC 608 4/21/2000 

SW Horseshoe EB 430 2,285 EB 430 5/3/2000 

Dawson GB 669 3,152 GB 668 5/22/2000 

Durango GB 667 3,105 GB 668 5/22/2000 

Gunnison GB 668 3,100 GB 668 5/22/2000 2003 

EW 878 EW 878 1,585 EW 878 7/03/2000 2001 

MC 837 MC 837 1,524 EW 878 7/03/2000 

Aspen GC 243 3,065 GC 243 1/27/2001 2002 

Lost Ark EB 421 2,960 EB 421 1/31/2001 2002 

Pilsner EB 205 1,108 EB 205 5/02/2001 2001 
129 

Project Name Area/Block 

Water 

Depth 

(ft)1 Field 

Field 

Discovery 

Date2

Year of 

First 

Production 

Year of 

Last 

Production 

Front Runner GC 339 3,330 GC 339 6/08/2001 

Balboa EB 597 3,352 EB 597 7/02/2001 

San Patricio AT 153 4,785 AT 153 8/09/2001 

GB 244 GB 244 2,130 GB 244 8/15/2001 

Boris GC 282 2,378 GC 282 9/29/2001 2003 

Red Hawk GB 877 5,334 GB 877 10/18/2001 

Timberwolf MC 555 4,749 MC 555 10/30/2001 

VK 962 VK 962 4,677 VK 962 11/15/2001 

Hawkes MC 509 4,174 MC 509 11/20/2001 

Merganser AT 37 8,015 AT 037 11/28/2001 

VK 917 VK 917 4,370 VK 917 12/08/2001 

Hornet GC 379 2,076 GC 379 12/14/2001 

Ness GC 507 3,947 GC 507 12/27/2001 

Poseiden (MC) MC 772 5,567 MC 728 6/30/2002 

Triton MC 728 5,373 MC 728 6/30/2002 

Falcon EB 579 3,638 EB 579 9/29/2002 2003 

Goose MC 751 1,624 MC 751 12/15/2002 2003 

Tomahawk EB 759 4,114 EB 759 1/28/2003 

Raptor EB 668 3,710 EB 668 9/13/2003 

Atlas LL 50 8,934 

Blind Faith MC 696 6,989 

Cascade WR 206 8,143 

Chinook WR 469 8,831 

Constitution GC 680 5,071 

Entrada GB 782 4,690 

Glider GC 248 3,440 

Grand Canyon GC 141 1,720 

Great White AC 857 8,717 

Ida/Fastball VK 1003 4,942 

Jubilee AT 349 8,825 

Kepler/Na Kika MC 383 5,759 

Lorien GC 199 2,315 

Mighty Joe Young GC 737 4,415 

Navarro GC 37 2,019 

Puma GC 823 4,129 

Shenzi GC 653 4,238 

Spiderman DC 621 8,087 

St. Malo WR 678 7,036 
130 

Project Name Area/Block 

Water 

Depth 

(ft)1 Field 

Field 

Discovery 

Date2

Year of 

First 

Production 

Year of 

Last 

Production 

Sturgis AT 183 3,710 

Tahiti GC 640 4,292 

Thunder Horse 

North MC 776 5,660 

Trident AC 903 9,743 

Tubular Bells MC 725 4,334 

Vortex AT 261 8,344 

1

 Water depths shown reflect depth at facility. If project is subsea or undeveloped, water depth reflects depth of deepest well 

location in project. 2

 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. 
131 

Appendix C. 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 

Sale 

Number Sale Location Sale Date 

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 

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 
132 

Sale 

Number Sale Location Sale Date 

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 

172 CGOM 3/17/1999 

Sale 

Number Sale Location Sale Date 

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 

187 WGOM 8/20/2003 

189 EGOM 12/10/2003 

190 CGOM 3/17/2004 

192 WGOM 

194 CGOM 

196 WGOM 

197 EGOM 

198 CGOM 

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 
133 

Appendix D. Deepwater Studies Program.

Active Studies [MMS Study Number] 

Deepwater Program: Understanding the Processes that Maintain the Oxygen Levels in the Deep Gulf of 

Mexico [85080] 

Deepwater Program: Survey of Deepwater Currents in the Western Gulf of Mexico [71562] 

Deepwater Program: Marathon - Case study (Numerical Modeling) (Subscription) [16073 B] 

Deepwater Program: Conoco - Eddies (EJIP - data) (Membership) [16074 B] 

Deepwater Program: Labor Migration and the Deepwater Oil Industry in Houma [16804 G] 

Deepwater Program: Observation of Deepwater Manifestation of Loop Current Rings [16805 B] 

Deepwater Program: Deepwater Currents at 92° W [16807 B] 

Deepwater Program: An Analysis of the Socioeconomic Effects of OCS Activities on Ports and 

Surrounding Areas in the Gulf of Mexico Region [19957 G] 

Deepwater Program: Labor Migration and the Deepwater Oil Industry [19958 G] 

Deepwater Program: 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] 

Deepwater Program: Assessing and Monitoring Industry Labor Needs [30898 G] 

Deepwater Program: Benefits and Burdens of OCS Deepwater Activities on Selected Communities and 

Local Public Institutions [30899 G] 

Deepwater Program: Development of a Deepwater Environmental Data Model [30917 I] 

Deepwater Program: OCS-Related Infrastructure in the Gulf of Mexico [30955 G] 

Deepwater Program: Northern Gulf of Mexico Continental Slope Habitats and Benthic Ecology 

[30991 C] 

Deepwater Program: Study of Subsurface, High-Speed Current Jets in the Deep Water Region of the 

Gulf of Mexico [31026 B] 

Deepwater Program: Analysis and Validation of a Mechanism that Generates Strong Mid-depth Currents 

and a Deep Cyclone Gyre in the Gulf of Mexico [31027 B] 

Deepwater Program: 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] 

Deepwater Program: 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] 

Deepwater Program: Effects of Oil and Gas Exploration and Development at Selected Continental Slope 

Sites in the Gulf of Mexico [31034 E] 

Deepwater Program: Joint Industry Project, Gulf of Mexico Comprehensive Synthetic Based Muds 

Monitoring Program [31069 E] 

Deepwater Program: 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] 

Deepwater Program: The Technology and Economics of Deepwater Production Projects [31019 G] 

Deepwater Program: Exploratory Study of Deepwater Currents in the Gulf of Mexico [31152 B] 
134 

Completed Studies [MMS Study Number] 

Deepwater Program: 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 Synthetic-Based Drilling Fluids

Deepwater Program: Workshop for Modeling Demographic and Socioeconomic Change in Local Coastal 

Areas in the Gulf of Mexico Region [19959 G] 

Deepwater Program: 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

Deepwater Program: 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 

Deepwater Program: 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 

Deepwater Program: 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

Deepwater Program: 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 

Deepwater Program: 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

Deepwater Program: 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

Study in the Procurement Process

Deepwater Program: Survey of Deepwater Currents in the Eastern Gulf of Mexico 

All reports are available at our web site — 

http://www.gomr.mms.gov/homepg/regulate/environ/deepenv.html. 
135 

Appendix E. Companies Defined as Majors in this Report. 

Group Name Company Name MMS Number 

Amoco Canyon Company 00735 

Amoco Corporation 02244 

Amoco Foundation, Inc. 01679 

Amoco Pipeline Company 00751 

Amoco Production Company 00114 

ARCO Pipe Line Company 00486 

Atlantic Refining Company 00002 

Atlantic Richfield Company 00002 

Atlantic Richfield Company 00967 

BP Alaska Exploration Inc. 00301 

BP America Production Company 21396 

BP America Production Company 00114 

BP Americas Inc. 21372 

BP Amoco Corporation 02367 

BP Corporation North America Inc. 02367 

BP Exploration & Oil Inc. 01680 

BP Exploration & Production Inc. 02481 

BP Exploration Inc. 00593 

BP Exploration USA Inc. 00120 

BP Prod. Corp. 02350 

BP Oil Company 01680 

BP Oil Corporation 00120 

BP Pipelines (North America) Inc. 00751 

BP Prod Corp 02350 

Mardi Gras Endymion Oil Pipeline Company LLC 02529 

Mardi Gras Transportation System Inc. 02527 

Pan American Petroleum Corp 00114 

Sohio Alaska Petroleum Company 00113 

Sohio Natural Resources 00113 

Sohio Petroleum Company 00113 

Sohio Petroleum Company 00593 

Stanolind Oil and Gas Company 00114 

BP 

Vastar Offshore, Inc. 02316 
136 

Group Name Company Name MMS Number 

Vastar Pipeline, LLC 02317 

Vastar Resources, Inc. 01855 

California Oil Company 00078 

Chevron Corporation 02335 

Chevron Natural Gas Pipe Line Company 02626 

Chevron Oil Company 00078 

Chevron Oil Company of the Netherlands 01443 

Chevron PBC Inc. 01750 

Chevron Pipe Line Company 00400 

Chevron Texaco Corp. 21391 

Chevron U.S.A. Inc. 00078 

Chevron U.S.A. LP 02544 

ChevronTexaco Corporation 02335 

Equilon Pipeline Company LLC 01107 

Equilon Pipeline Company LLC 02289 

Four Star Oil & Gas Company 00005 

Four Star Oil and Gas Company 00005 

Getty Oil Company 00005 

Getty Pipeline, Inc. 01107 

Getty Reserve Oil, Inc. 00578 

Gulf Oil Corporation 00112 

Pennzoil Exploration and Production Company 01750 

Pennzoil Petroleum Company 01750 

Seaboard Oil Company 00025 

Texaco Exploration and Production 00771 

Texaco Inc. 00040 

Texaco Oils Inc. 00857 

Texaco Pipeline Inc. 01107 

Texaco Pipelines LLC 21200 

Texaco Producing Inc. 00771 

Texaco Seaboard Inc. 00025 

Texaco Trading and Transportation Inc. 02020 

ChevronTexaco 

Texas Company 00040 
137 

Group Name Company Name MMS Number 

Exxon Asset Holdings LLC 02356 

Exxon Asset Management Company 02295 

Exxon Corporation 00276 

Exxon Mobil Corporation 00276 

Exxon Mobil Oil Corporation 00039 

Exxon Mobil Pipeline Company 00103 

Exxon Pipeline Company 00103 

Humble Pipe Line Company 00103 

Mobil Corporation 02221 

Mobil E&P U.S. Development Corporation 02203 

Mobil E&P U.S. Development Fund, L.P. 02209 

Mobil Eugene Island Pipeline Company 00883 

Mobil Exploration and Producing North America Inc. 01055 

Mobil Foundation, Inc. 01933 

Mobil NOC Inc. 00021 

Mobil Oil Corporation 00039 

Mobil Oil Exploration & Producing Southeast Inc. 00540 

Mobil Producing Texas & New Mexico Inc. 00565 

Mobil GC Corporation 00565 

Mobil-TransOcean Company 00637 

Newmont Oil Company 00021 

Socony Mobil Oil Co 00039 

ExxonMobil 

Superior Oil Company 00047 

Coral Offshore Gathering LLC 02253 

Enterprise Oil Gulf of Mexico Inc. 02117 

Enterprise Oil Louisiana Inc. 02118 

MG Gas Services Inc. 02128 

Mississippi Canyon Gas Pipeline, LLC 02254 

Shell Consolidated Energy Resources Inc. 01940 

Shell Deepwater Development Inc. 02139 

Shell Deepwater Production Inc. 02140 

Shell Energy Resources Inc. 00688 

Shell Frontier Oil & Gas Inc. 01728 

Shell 

Shell Gas Gathering Company 02168 
138 

Group Name Company Name MMS Number 

Shell Gas Gathering Company, LLC 02253 

Shell Gas Gathering LLC 02253 

Shell Gas Pipeline Company 01070 

Shell Gas Pipeline Company LLC 02254 

Shell GOM Pipeline Company LLC 02621 

Shell Gulf of Mexico Inc. 02117 

Shell Land & Energy Company 01967 

Shell Offshore Inc. 00689 

Shell Offshore Properties and Capital II, Inc. 02128 

Shell Oil & Gas Investment Limited Partnership 01839 

Shell Oil Company 00117 

Shell Onshore Ventures Inc. 01845 

Shell Pipe Line Corporation 00124 

Shell Seahorse Company 02147 

Shell Western E&P Inc. 00832 

SWEPI LP 00832 

Tejas Offshore Gathering LLC 02253 

Note: Some companies in this list may no longer be qualified with the MMS. 
139 

Appendix F. Number of Deepwater Production Facilities Installed Each Year (including 

Plans through 2006). 

Year Fixed 

Platform 

Compliant 

Tower TLP Small TLP Spar Truss Spar 

SemiFPS Subsea 

1979 1 0 0 0 0 0 0 0 

1980 0 0 0 0 0 0 0 0 

1981 0 0 0 0 0 0 0 0 

1982 0 0 0 0 0 0 0 0 

1983 0 0 0 0 0 0 0 0 

1984 0 1 0 0 0 0 0 0 

1985 0 0 0 0 0 0 0 0 

1986 0 0 0 0 0 0 0 0 

1987 0 0 0 0 0 0 0 0 

1988 0 0 0 0 0 0 1 0 

1989 1 0 1 0 0 0 0 0 

1990 0 0 0 0 0 0 0 0 

1991 1 0 0 0 0 0 0 0 

1992 0 0 0 0 0 0 0 1 

1993 0 0 0 0 0 0 0 2 

1994 1 0 1 0 0 0 0 2 

1995 0 0 0 0 0 0 1 2 

1996 0 0 1 0 0 0 0 3 

1997 0 0 1 0 1 0 0 2 

1998 0 1 0 1 0 0 0 3 

1999 1 0 2 1 1 0 0 7 

2000 0 1 0 0 1 0 0 6 

2001 0 0 1 2 0 1 0 12 

2002 0 0 0 0 0 2 0 13 

2003 0 0 0 2 0 2 1 9 

2004* 0 0 1 0 1 2 1 10 

2005* 0 0 0 0 0 1 0 10 

2006* 0 0 0 0 0 0 1 10 

* Estimated numbers. 
140 

Appendix G. Subsea Completions.

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

AC 24 608054000501 Exxon Mobil Corporation 2/03/2002 4,856

BA A 17 427044034500 Spinnaker Exploration Company LLC 8/10/2003 140

DC 133 608234000200 BP Exploration & Production Inc 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 168 608044016600 Walter Oil & Gas Corporation 7/16/1997 450

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 Samedan Oil Corporation 5/12/2002 2,740

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 8/11/2001 3,678

EB 602 608044022500 Kerr-McGee Oil & Gas Corporation 9/07/2001 3,644

EB 623 608044023400 Pioneer Natural Resources USA Inc 12/30/2002 3,412

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 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 231 177034063800 Energy Resource Technology Inc 5/24/1993 122

EC 235 177034047300 Chevron USA Inc 11/16/1986 121

EC 305 177044100900 Remington Oil and Gas Corporation 9/10/2001 197

EC 328 177044080800 Maritech Resources Inc 2/13/1997 243

EC 335 177044030300 Devon Energy Production Company LP 7/15/1976 272

EC 341 177044067100 Walter Oil & Gas Corporation 10/21/1988 275
141 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

EC 374 177044101700 Energy Resource Technology Inc 7/17/2002 425

EC 378 608074015700 Energy Partners Ltd 1/27/1997 495

EC 380 177044102600 Walter Oil & Gas Corporation 6/28/2001 538

EI 294 177104126801 B T Operating Co 10/06/1991 214

EI 320 177104128700 Forest Oil Corporation 12/31/1993 244

EI 322 177104134100 BP America Production Company 10/30/1991 242

EI 349 177104100500 NCX Company LLC 11/23/1990 337

EI 364 177104138000 The Louisiana Land and Exploration 

Company 10/14/1994 357

EI 386 177104147500 Tarpon Offshore LP 2/24/2002 417

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 914 608105002200 Tatham Offshore Inc 8/11/1993 946

EW 917 608105006500 Marathon Oil Company 4/08/1998 1,195

EW 921 608105008104 Eni Petroleum Co Inc 8/16/2002 1,692

EW 963 608105006000 Marathon Oil Company 5/25/1998 1,740

EW 963 608105006800 Marathon Oil Company 6/29/1998 1,758

EW 966 608104010001 Mariner Energy Inc 5/12/2000 1,853

EW 989 608104008600 Kerr-McGee Corporation 11/02/1994 565

EW 989 608104008701 Kerr-McGee Corporation 9/28/1995 565

EW 999 608104003202 Placid Oil Company 6/08/1988 1,462

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 70 608074007001 Newfield Exploration Company 9/29/1997 750

GB 71 608074013000 Newfield Exploration Company 4/30/1995 750

GB 73 608074021200 Mariner Energy Inc 4/06/2000 745

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
142 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

GB 139 608074064501 W & T Offshore Inc 11/25/2002 550

GB 152 608074020800 Walter Oil & Gas Corporation 7/07/1999 619

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 200 608074021100 Amerada Hess Corporation 11/29/2000 1,736

GB 201 608074023701 Amerada Hess Corporation 11/02/2002 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 240 608074013100 Samedan Oil Corporation 1/29/1996 832

GB 341 608074025401 Shell Offshore Inc 6/14/2003 2,013

GB 341 608074019104 Shell Offshore Inc 7/30/2003 2,015

GB 367 608074064101 Mariner Energy Inc 2/10/2001 1,122

GB 387 608074014001 Newfield Exploration Gulf Coast Inc 3/03/1996 2,081

GB 388 608074005400 Newfield Exploration Gulf Coast Inc 3/19/1995 2,097

GB 388 608074008401 Newfield Exploration Gulf Coast Inc 5/01/1995 2,097

GB 388 608074015601 Newfield Exploration Gulf Coast Inc 2/25/1997 2,096

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
143 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

GB 602 608074014401 Shell Offshore Inc 12/28/1999 3,708

GB 602 608074019301 Shell Offshore Inc 2/27/2001 3,708

GC 20 608114021300 Shell Gulf of Mexico Inc 12/10/1999 880

GC 29 608114009100 Placid Oil Company 6/17/1989 1,526

GC 31 608114004701 EP Operating Limited Partner 8/07/1988 2,243

GC 31 608114009600 EP Operating Limited Partner 1/20/1989 2,234

GC 60 608114020101 Mobil Oil Exploration & Producing 6/22/1996 868

GC 110 608114020600 Shell Offshore Inc 1/23/1996 1,730

GC 113 608115013100 Shell Deepwater Development Inc 7/17/1999 1,968

GC 113 608115012701 Shell Deepwater Development 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 608114020401 Chevron USA Inc 12/20/1995 1,042

GC 136 608114029600 Chevron USA Inc 11/19/2002 990

GC 155 608114022803 Shell Offshore Inc 6/12/2002 1,890

GC 155 608114031100 Shell Offshore Inc 6/23/2002 1,939

GC 200 608114021800 BP Exploration & Production Inc 11/10/1997 2,670

GC 200 608114021600 BP Exploration & Production Inc 12/07/1997 2,670

GC 200 608114020501 BP Exploration & Production Inc 6/29/1998 2,670

GC 200 608114021901 BP Exploration & Production Inc 2/27/1999 2,670

GC 200 608114028900 BP Exploration & Production Inc 1/25/2001 2,672

GC 236 608114025201 Chevron USA Inc 2/08/2001 1,987

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 BP Exploration & Production Inc 3/02/1998 2,670

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 472 608114030003 Eni Petroleum Co Inc 8/19/2001 3,780
144 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

GC 473 608114027300 Eni Petroleum Co Inc 9/15/2001 3,840

GC 516 608114030101 Eni Petroleum Co Inc 10/02/2001 3,839

GI 32 177174011700 BP America Production Company 3/09/1980 98

GI 41 177174009600 BP America Production Company 9/25/1978 91

GI 41 177174009700 BP America Production Company 10/08/1978 91

GI 41 177174009500 BP America Production Company 11/08/1978 91

GI 43 177174009800 BP America Production Company 8/01/1978 114

GI 47 177174009300 BP America Production Company 5/14/1978 88

GI 47 177174018500 BP America Production Company 5/20/1986 97

GI 101 177184010500 Walter Oil & Gas Corporation 9/29/2002 215

GI 109 177184009600 Walter Oil & Gas Corporation 10/16/2000 280

HI A 309 427114070100 El Paso Production Oil & Gas 

Company 1/24/1995 213

HI A 316 427114084301 El Paso Production Oil & Gas 

Company 11/23/2002 217

HI A 345 427114083000 Seneca Resources Corporation 7/26/2003 238

HI A 355 427114084100 Newfield Exploration Company 12/15/2002 285

HI A 370 427114065100 Kerr-McGee Oil & Gas Corporation 10/30/1990 375

HI A 378 427114075700 Kerr-McGee Oil & Gas Corporation 7/28/1996 360

HI A 378 427114080601 Kerr-McGee Oil & Gas Corporation 4/01/1999 332

HI A 441 427094109900 Remington Oil and Gas Corporation 9/25/2000 168

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
145 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

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 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 BP Exploration & Production Inc 8/22/2001 6,420

MC 217 608174090900 BP Exploration & Production Inc 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 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 322 608174094201 Walter Oil & Gas Corporation 8/12/2001 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 Shell Offshore Inc 8/11/2002 5,735

MC 383 608174094702 Shell Offshore Inc 8/26/2002 5,739

MC 401 608174034600 Kerr-McGee Oil & Gas Corporation 7/25/1993 1,700

MC 401 608174032901 Kerr-McGee Oil & Gas Corporation 8/25/1993 1,367 

MC 401 608174096100 Anadarko Petroleum Corporation 5/17/2003 1,139

MC 429 608174051300 BP Exploration & Production Inc 10/23/2002 6,240

MC 429 608174095402 Shell Offshore Inc 2/02/2003 6,101
146 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

MC 429 608174084404 Shell Offshore 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 445 608174042900 Kerr-McGee Oil & Gas Corporation 10/04/1993 2,094

MC 445 608174047300 Kerr-Mcgee Oil & Gas Corporation 7/23/1994 2,095

MC 485 608174041600 Newfield Exploration Gulf Coast Inc 5/24/1993 1,438

MC 520 608174054601 Shell Offshore Inc 7/01/2002 6,738

MC 522 608174096900 Shell Offshore Inc 11/26/2002 6,932

MC 522 608174097000 Shell Offshore Inc 12/16/2002 6,934

MC 522 608174085802 Shell Offshore Inc 12/31/2002 6,940

MC 608 608174098400 Shell Offshore 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 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 764 608174058701 BP Exploration & Production Inc 4/06/2000 3,283

MC 765 608174100501 Shell Offshore Inc 7/18/2003 3,642

MC 766 608174096302 Shell Offshore Inc 9/11/2003 3,637

MC 807 608174038800 Shell Offshore Inc 3/25/1996 2,956

MC 837 608174092401 Walter Oil & Gas Corporation 6/22/2001 1,524

MC 890 608174082800 Shell Offshore Inc 9/08/1999 3,875

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
147 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

MP 131 177254060100 ATP Oil & Gas Corporation 11/03/1998 165

MP 145 177254047300 Conoco Inc 12/30/1985 213

MP 149 177254058901 Walter Oil & Gas Corporation 9/06/1994 220

MP 150 177254069600 Walter Oil & Gas Corporation 12/3/2000 245

MP 260 177244081400 Devon SFS Operating Inc 4/26/1999 315

MP 263 177244089600 Magnum Hunter Production Inc 3/31/2003 280

MP 281 177244069100 Walter Oil & Gas Corporation 7/28/1994 293

MP 286 177244090400 Walter Oil & Gas Corporation 11/17/2003 292

MP 291 177244056600 Allied Natural Gas Corporation 7/04/1992 272

MU 806 427024024500 Apache Corporation 11/30/1995 164

MU A 124 427124010701 Walter Oil & Gas Corporation 6/25/1998 381

PN 996 427134009900 F-W Oil Exploration LLC 11/14/2003 159

PN 1010 427014005000 Walter Oil & Gas Corporation 6/27/1999 128

PN A 9 427134050200 Denbury Offshore Inc 11/05/2003 201

PN A 12 427134009600 Apache Corporation 11/01/2001 250

SP 32 177212050500 Devon Louisiana Corporation 6/12/2002 115

SS 176 177114099800 Chevron USA Inc 9/29/1990 100

SS 204 177110067200 Anadarko E&P Company LP 3/24/1968 100

SS 321 177124057000 ATP Oil & Gas Corporation 5/29/1997 323

SS 326 177124058700 Walter Oil & Gas Corporation 5/11/1998 364

SS 361 177124054900 Anadarko Petroleum Corporation 7/08/1998 405

ST 169 177154032600 Samedan Oil Corporation 4/27/1980 88

ST 169 177154062300 Samedan Oil Corporation 6/01/1985 102

ST 177 177154007800 Chevron USA Inc 11/06/1976 144

ST 212 177164031200 El Paso Production Company 11/06/2003 140

ST 239 177164031300 Walter Oil & Gas Corporation 9/25/2003 162

ST 248 177164029700 PRS Offshore LP 6/04/2002 178

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 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
148 

Area Block API Number Operator Completion 

Date 

Water 

Depth 

(ft) 

VK 862 608164021600 Walter Oil & Gas Corporation 11/15/1995 1,067

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 944 608164032200 Walter Oil & Gas Corporation 12/05/1997 730

VK 944 608164040602 Walter Oil & Gas Corporation 5/02/2002 730

VK 986 608164022800 Walter Oil & Gas Corporation 12/23/1995 893

VK 986 608164040800 Walter Oil & Gas Corporation 5/26/2002 895

VR 116 177054107201 Offshore Energy I LLC 4/19/1998 55

VR 215 177054028500 Newfield Exploration Company 12/22/1978 140

VR 246 177054034600 Chevron USA Inc 3/30/1981 155

VR 302 177064021701 Nexen Petroleum USA Inc 2/20/1977 197

VR 320 177064064200 Kerr-McGee Oil & Gas Corporation 11/12/1991 206

VR 332 177064091100 PRS Offshore LP 10/19/2002 223

WC 459 177024062900 Conoco Inc 5/16/1985 135

WC 548 177024106000 Walter Oil & Gas Corporation 6/14/1994 185

WC 584 177024085700 Walter Oil & Gas Corporation 3/03/1989 237

WC 592 177024106301 Walter Oil & Gas Corporation 7/11/1995 252

WC 635 177024127500 ATP Oil & Gas Corporation 1/08/2001 360

WC 638 177024116900 Denbury Offshore Inc 11/06/1998 373

WD 45 177190038200 Nexen Petroleum USA Inc 2/11/1959 50

WD 45 177190038300 Nexen Petroleum USA Inc 2/26/1959 72

WD 45 177190038402 Nexen Petroleum USA Inc 12/08/1981 50

WD 62 177194027900 Pioneer Natural Resources USA Inc 8/13/1985 130

WD 70 177190062800 BP America Production Company 2/02/1958 143

WD 70 177190063000 BP America Production Company 10/05/1961 143

WD 71 177190061900 BP America Production Company 7/23/1961 142

WD 77 177194065504 ATP Oil & Gas Corporation 8/29/1999 187

WD 106 177194056800 Walter Oil & Gas Corporation 12/28/1994 234

WD 106 177194070300 Walter Oil & Gas Corporation 6/14/2001 254

WD 107 177194056400 Walter Oil & Gas Corporation 1/02/1996 222

WD 111 177204013701 Walter Oil & Gas Corporation 4/23/1997 260
149 

Appendix H. Average Annual GOM Oil and Gas Production. 

Year 

Shallowwater Oil 

(MBOPD) 

Deepwater 

Oil 

(MBOPD) 

Total GOM 

Oil 

(MBOPD) 

Shallowwater Gas 

(BCFPD) 

Deepwater 

Gas 

(BCFPD) 

Total GOM 

Gas 

(BCFPD) 

1947 0 0 0 0.0 0.0 0.0

1948 0 0 0 0.0 0.0 0.0

1949 0 0 0 0.0 0.0 0.0

1950 1 0 1 0.0 0.0 0.0

1951 1 0 1 0.0 0.0 0.0

1952 2 0 2 0.1 0.0 0.1

1953 3 0 3 0.1 0.0 0.1

1954 7 0 7 0.2 0.0 0.2

1955 11 0 11 0.2 0.0 0.2

1956 19 0 19 0.2 0.0 0.2

1957 32 0 32 0.3 0.0 0.3

1958 54 0 54 0.4 0.0 0.4

1959 81 0 81 0.6 0.0 0.6

1960 111 0 111 0.8 0.0 0.8

1961 153 0 153 0.9 0.0 0.9

1962 210 0 210 1.2 0.0 1.2

1963 264 0 264 1.5 0.0 1.5

1964 305 0 305 1.8 0.0 1.8

1965 372 0 372 2.0 0.0 2.0

1966 480 0 480 2.7 0.0 2.7

1967 574 0 574 3.5 0.0 3.5

1968 695 0 695 4.4 0.0 4.4

1969 801 0 801 5.3 0.0 5.3

1970 901 0 901 6.6 0.0 6.6

1971 1,029 0 1,029 7.5 0.0 7.5

1972 1,022 0 1,022 8.2 0.0 8.2

1973 1,002 0 1,002 9.1 0.0 9.1

1974 926 0 926 9.4 0.0 9.4

1975 848 0 848 9.4 0.0 9.4

1976 824 0 824 9.7 0.0 9.7

1977 778 0 778 10.3 0.0 10.3

1978 757 0 757 11.6 0.0 11.6
150 

Year 

Shallowwater Oil 

(MBOPD) 

Deepwater 

Oil 

(MBOPD) 

Total GOM 

Oil 

(MBOPD) 

Shallowwater Gas 

(BCFPD) 

Deepwater 

Gas 

(BCFPD) 

Total GOM 

Gas 

(BCFPD) 

1979 720 2 721 12.8 0.0 12.8 

1980 711 14 725 13.0 0.0 13.1 

1981 711 10 721 13.4 0.0 13.4 

1982 748 36 784 12.7 0.0 12.8 

1983 806 72 878 11.1 0.1 11.2 

1984 905 68 973 12.4 0.1 12.5 

1985 904 58 962 11.1 0.1 11.2 

1986 924 52 976 11.0 0.1 11.1 

1987 852 47 899 12.3 0.1 12.5 

1988 791 36 827 12.5 0.1 12.6 

1989 743 27 770 2.7 0.1 12.7 

1990 720 33 753 3.4 0.1 13.5 

1991 746 63 808 2.8 0.2 12.9 

1992 734 102 836 12.5 0.2 12.8 

1993 746 101 847 12.5 0.3 12.8 

1994 748 115 862 12.8 0.4 13.3 

1995 795 151 947 12.6 0.5 13.1 

1996 814 198 1,012 13.2 0.8 14.0 

1997 831 296 1,127 13.1 1.0 14.1 

1998 781 436 1,218 12.3 1.5 13.8 

1999 740 617 1,357 11.6 2.3 13.9 

2000 691 743 1,434 10.9 2.7 13.6 

2001 661 853 1,514 10.6 3.2 13.8 

2002* 603 959 1,562 8.8 3.6 12.3 

* Estimated values for the year 2002. 
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.