Deepwater Gulf of Mexico:

America's Emerging Frontier

OCS Report

MMS 2000-022

MMS Minerals Management Service

Gulf of Mexico OCS Region

U.S. Department of the Interior
ON COVER—Maximum historical oil production rates for Gulf of Mexico wells. Taller

bars indicate higher production rates. The data show numerous deepwater oil wells

produced at significantly higher rates than ever seen in the Gulf of Mexico.
OCS Report

MMS 2000-022

Deepwater Gulf of Mexico:

America’s Emerging Frontier

Richie D. Baud

Robert H. Peterson

Carey Doyle

G. Ed Richardson

U.S. Department of the Interior

Minerals Management Service New Orleans

Gulf of Mexico OCS Regional Office April 2000

iii

Contents 

Page

Preface, ix

Introduction, 1

Leasing, 21

Drilling and Development, 31

Reserves and Production, 46

Summary and Conclusions, 66

Contributing Personnel, 78

References, 79

Appendix A - Announced Deepwater Discoveries and Fields, 80

Appendix B - Companies Defined as Majors in this Report, 83

Appendix C - Subsea Completions, 85
iv

Figures 

Page

 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 DWRR zones, 3

 2. Progressive deepwater 3-D seismic permit coverage from 1992 through 1999, 6

3. Deepwater Gulf of Mexico 3-D seismic permit coverage from 1992

through 1999, 7

 4. New deepwater plays in the Gulf of Mexico, 8

 5. Deepwater leases issued in the Gulf of Mexico, 9

 6. Active leases in the Gulf of Mexico, 10

 7. Deepwater environmental and administrative features, 12

 8. Deepwater discoveries in the Gulf of Mexico, 13

 9. Ownership of deepwater discoveries, 14

10. Estimated volumes of 39 proved deepwater fields, 15

11. Onshore service bases for existing deepwater structures, 16

12. Onshore service bases for pending deepwater plans, 17

13. Oil and gas pipelines with diameters greater than or equal to 20 inches, 19

14. Deepwater oil and gas pipelines, 20

15. Number of leases issued each year subdivided by DWRR water depth

categories, 22

16a. Number of leases bid in each deepwater interval, 23

16b. Total bid amounts in deepwater intervals, 23

16c. Average bid amount per block in deepwater intervals, 23

17. Rejected shallow- and deepwater Gulf of Mexico bids, 24

18. Ownership of deepwater leases, 25

19. Leasing impact of recent company mergers and probable future mergers, 28

20. Anticipated lease expirations in the Gulf of Mexico, 29

21. Average number of rigs drilling in the deepwater Gulf of Mexico, 32

22. Approximate number of deepwater Gulf of Mexico rigs subdivided

according to their maximum water depth capabilities, 32

23. Deepwater exploratory wells drilled in the Gulf of Mexico, subdivided by

water depth, 33

24. Deepwater development wells drilled in the Gulf of Mexico, subdivided by

water depth, 33

25. Deepwater exploratory wells drilled in the Gulf of Mexico, 34

26. Deepwater development wells drilled in the Gulf of Mexico, 35

27. Deepwater POE’s approved, deepwater DOCD’s approved, and DWOP’s

received in the Gulf of Mexico since 1992, 37

28. Maximum wellbore true vertical depth (TVD) drilled each year, 38

29. Maximum water depth drilled each year, 38

30. Deepwater development systems, 40

31. Number of subsea completions each year, 43

32. Maximum water depths of subsea completions each year, 43
v

Figures – continued Page

33. Number of shallow- and deepwater subsea completions each year since

1992, 44

34. Length of subsea tiebacks, 44

35. Deepwater oil and gas pipelines (a) less than or equal to 12 inches in

diameter, and (b) greater than 12 inches in diameter, 45

36a. Proved reserve additions, 47

36b. Proved and unproved reserve additions, 47

36c. Average field size using proved and unproved reserves, 48

37. Number of deepwater field discoveries and resulting number of producing

fields, 49

38. Number of deepwater field discoveries and new hydrocarbons found (MMS

reserves, MMS resources, and industry-announced discoveries), 49

39. BOE added (reserves, resources, and industry-announced discoveries), 51

40. Relative volume of production from each Gulf of Mexico lease. Bar heights

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

that time interval, 52

41. Comparison of yearend shallow- and deepwater (a) oil production and

(b) gas production, 54

42. Contributions from subsea completions toward total deepwater (a) oil

production and (b) gas production, 55

43. Comparison of major companies and nonmajor companies in terms of

deepwater (a) oil production and (b) gas production, 57

44. Percentage of deepwater (a) oil production and (b) gas production from

nonmajor oil and gas companies, 58

45. Contributions from each major oil company toward total deepwater (a) oil

production and (b) gas production, 59

46. Maximum production rates for a single well within each water depth

category for deepwater (a) oil production and (b) gas production, 60

47. Maximum historical oil production rates for Gulf of Mexico wells, 62

48. Maximum historical gas production rates for Gulf of Mexico wells, 63

49. Maximum oil production rates for Gulf of Mexico wells that produced over

5,000 BOPD, 64

50. Maximum gas production rates for Gulf of Mexico wells that produced over

75,000 MCFPD, 65

51. Deepwater projects that began production in 1999 and those expected to

begin production by yearend 2004, 67

52. Deepwater lease activity and oil prices, 69

53a. Time lag from leasing to first well for producing deepwater fields, 70

53b. Time lag from leasing to qualifying for producing deepwater fields, 70

53c. Time lag from leasing to first production for producing deepwater fields, 70

53d. Time lag from leasing to first production, qualification, and first production

for all deepwater wells, 71

54. Activity on deepwater leases, 73
vi

Figures – continued Page

55a. Relationship between number of leases bid upon (1974-1989) and number

of leases drilled, 74

55b. Relationship between number of leases bid upon and resulting number of

producing leases, 74

55c. Relationship between number of leases drilled and resulting number of

producing leases, 74

55d. Relationship between number of qualifying leases and resulting number of

producing leases, 74

56. Anticipated effect of rig constraints on lease evaluations, 76
vii

Table 

Page

1. Development Systems of Productive Deepwater GOM Fields, 41
viii
ix

Preface 

The deepwater of the Gulf of Mexico has emerged as a world class oil and gas province in

the last four years. Leasing, exploration, and production activity accelerated rapidly since

MMS first published MMS Report 97-0004 in 1997 to herald the arrival of the deepwater

of the Gulf of Mexico as America’s new frontier.

In 1999, total Gulf of Mexico oil production reached an estimated 494 million barrels after

hovering around 300 million barrels a year for much of the decade. The increase has come

from the deepwater and was highlighted in late 1999, when oil production from the

deepwater portion of the Gulf of Mexico exceeded that of the shallow water for the first

time in history. This historic change after 53 years of production in the Gulf of Mexico has

been driven by several major factors all coalescing in the late 1990’s.

High flow rate wells have driven the economics of projects and acted as a strong incentive

to explore and develop deepwater leases. The use of subsea well completions has also

contributed to the economics of deepwater projects. At the end of 1999 there were 186

subsea completions—62 of them in deepwater—and they accounted for 25 percent of all

deepwater oil production and 40 percent of deepwater gas production.

The deepwater Gulf has also seen a number of major technical and engineering

achievements. These achievements include such projects as subsea production in 5,000+

feet of water (Mensa, 1997), TLP production in 3,800 feet of water (Ursa, 1999), the first

spar production (Neptune, 1997), and the first mini-TLP production (Morpeth, 1998).

These technological advances, when combined with incentives passed by Congress under

the Deepwater Royalty Relief Act of 1995, have also led to a tremendous surge in

deepwater leasing. This act provided automatic royalty relief to new oil and gas leases

issued during 1996-2000. Between 1996 and 1999 more than 3,000 new leases were issued

in water depths of 200 meters or greater in the Gulf of Mexico, with more than 2,600 of

these in 800 meters of water or greater.

With 30 fields on production at the end of 1999, the deepwater of the Gulf of Mexico can

rightly claim to be America’s new frontier and has truly emerged as a world class

hydrocarbon province. Its future looks bright, as many new geologic trends are only now

seeing the first exploratory drilling. Truly, the deepwater will drive the new millenium.

Chris C. Oynes

Regional Director

Minerals Management Service

1

Introduction 

The deepwater Gulf of Mexico (GOM) has recently emerged as an important oil and gas

province and an integral part of the Nation’s oil and gas supply. A major milestone

occurred in late 1999 when more oil was produced from the deepwater GOM than from

the shallow-water GOM. This trend in increasing deepwater (water depths greater than

or equal to 1,000 ft) production is expected to continue, along with high levels of

exploratory drilling, development activity, pipeline construction, and shore support

activities. Deepwater GOM field discovery sizes have been several times larger than the

average shallow-water field discoveries. The deepwater fields have also been some of

the most highly prolific producers in the GOM.

This report is divided into five sections.

The Introductory section discusses

• highlights of current deepwater GOM activity.

The Leasing section discusses

• historical water depth and bidding trends in deepwater leasing,

• lease holdings of major oil companies compared with nonmajor oil companies,

• the impact of company mergers on deepwater exploration, 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,

• deepwater development systems including subsea completions, and

• the progress of deepwater infrastructure development.

The Reserves and Production section discusses

• historical deepwater reserve additions,

• historical trends in deepwater production,

• deepwater production from various companies, and

• high deepwater production rates.

The Summary and Conclusions section discusses

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

• large future reserve additions associated with recently announced discoveries,

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

• expected future increases in deepwater discoveries based on drilling of the

large deepwater lease inventory,

• limited deepwater rig availability,

• long lag times between leasing, drilling, and initial production, and

• difficulties evaluating deepwater leases before their terms expire.
2

The Gulf of Mexico OCS is divided into the Western, Central, and Eastern Planning

Areas (figure 1). The analysis in this report focuses on the Central and Western areas.

Many of the data presented in this report are subdivided according to water depth. These

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

congressionally mandated Deepwater Royalty Relief (DWRR) zones (200, 400, and 800

m) for reference. For purposes of this report, we define deep water as greater than or

equal to 1,000 ft-water depth.

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 paper 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.

More detailed definitions may be found in the annual Estimated Proved and Unproved

Oil and Gas Reserves, Gulf of Mexico, December 31, 1997 report (Crawford et. al.,

2000).

Throughout this report we refer to several deepwater fields by their nicknames.

Appendix A provides locations, operators, and additional information regarding these

fields. Note that the field’s identifying block number corresponds to the first lease

qualified by MMS as capable of production. Note also that the term “oil” refers to both

oil and condensate throughout this report and “gas” includes both associated and

nonassociated gas.

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 intense leasing at that time. In February 1997 there were 16 producing

deepwater fields, up from only 5 at the end of 1992. Industry was rapidly advancing into

deepwater and many of the anticipated fields have begun production since the 1997

report.
50 0 50 100 Miles

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 zones.

3000 meters

1000 meters

7500 feet

1000 feet

5000 feet

1500 feet

Keathley Canyon Lund

Lloyd Ridge

Henderson

Rankin

Walker Ridge

Green Canyon

De Soto Canyon Mississippi Canyon

Atwater Valley

Alaminos Canyon

Garden Banks

Destin Dome

The Elbow

Howell Hook

East Breaks

Dry Tortugas

Vernon Basin

TEXAS LOUISIANA

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FLORIDA

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WESTERN PLANNING AREA

EASTERN PLANNING AREA CENTRAL PLANNING AREA

East Breaks

Vernon Basin

Howell Hook

The Elbow

Destin Dome

Garden Banks

Alaminos Canyon

Atwater Valley

Mississippi Canyon De Soto Canyon

Green Canyon

Walker Ridge

Rankin

Lloyd Ridge

Henderson Lund Keathley Canyon

Dry Tortugas

HG99011

N 200 - 400 meters 400 - 800 meters >= 800 meters Royalty Relief Zones

3
4

At the end of 1999, there were 30 producing fields in the deepwater Gulf of Mexico, up

30 percent in just 12 months and up 88 percent since the original report (Cranswick and

Regg, 1997). In 1998 deepwater oil production rose 47 percent over 1997 production,

and in 1999 deepwater oil production increased an additional 41 percent over 1998

production. Similarly, deepwater gas production increased 47 percent in 1998, followed

by a 51 percent jump in 1999. Although U.S. oil production declined about 410,000

barrels a day from 1994 to 1998, the decline would have been nearly twice as large if the

deepwater GOM production had not increased by 321,000 barrels a day (Minerals

Management Service, 1999).

The dramatic shift toward high activity levels in the deepwater GOM occurred during the

last few years. This recent shift, however, has 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 (Exxon’s Lena field) came online. Deepwater

exploration and production continued to grow at an ever-increasing rate, leading to a

flurry of activity in the past five years. This report focuses on changes during the last

eight years, 1992-1999.

The growth in deepwater activity spans all phases of exploration and development,

including leasing, drilling, and production. There are approximately 7,600 active leases

in the Gulf of Mexico Outer Continental Shelf (OCS), 48 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

27 rigs drilling in deepwater in 1999, up from only 3 rigs in 1992. Likewise, deepwater

oil production rose about 550 percent and deepwater gas production increased almost

800 percent from December 1992 to December 1999.

All phases of exploration and development moved steadily into deeper waters over the

past eight years. We observed this trend in seismic activity, leasing, exploratory drilling,

field discoveries, and production. Major oil companies dominated deepwater leasing

activity until 1996, when nonmajors joined the trend. Major oil companies continue to

dominate deepwater oil and gas production, but we expect production from nonmajors to

surge in a few years, when anticipated discoveries on their 1996 through 1999 lease

acquisitions begin production.

The OCS Deep Water Royalty Relief (DWRR) Act (43 U.S.C. §1337) had a significant

impact on deepwater GOM activities. This legislation provides economic incentives for

operators to develop fields in water depths greater than 200 meters (656 ft). These

incentives include the automatic suspension of Federal royalty payments (for new leases

issued in 1996-2000) on the initial 17.5 million barrels of oil equivalent (MMBOE)

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

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

than 800 meters (2,624 ft) of water. Reduction of royalty payments is also available

through an application process for some deepwater fields that were leased prior to the

DWRR Act but had not yet gone on production. The automatic suspension volume
5

provision of the DWRR Act expires on November 28, 2000. Even if these incentives are

altered or eliminated on future leasing, leases acquired between November 28, 1995, and

November 28, 2000, will retain the incentives until their expiration.

The DWRR Act 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 greatly

reduces the inherent risks of hydrocarbon exploration. Figure 2 illustrates the recent

surge of seismic activity in the deepwater Gulf of Mexico during the last eight 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 extremely deep water). Note that many active deepwater leases were

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

2-D data sets were available).

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

activity. Figure 4 illustrates several new deepwater plays in the GOM. Although the

traditional deepwater mini-basin plays are far from mature (especially considering the

recently announced Crazy Horse discovery in Mississippi Canyon Block 778), the

Mississippi Fan Foldbelt, Perdido Foldbelt, and Tertiary Fan/Mesozoic Plays show that

the deepwater arena is still very much a frontier area. Although sparsely tested, the

Mississippi Fan Foldbelt Play shows great potential with announced discoveries at three

locations (prospects Mad Dog in Green Canyon Block 826, Neptune in Atwater Block

575, and Atlantis in Green Canyon Block 699). The Perdido Foldbelt Play is essentially

untested with only one shallow well in Alaminos Canyon Block 600 (Baha field). The

Tertiary Fan/Mesozoic Play is heavily leased, but also remains untested. These new

plays are large in areal extent, have multiple opportunities, and contain potentially huge

structural and/or stratigraphic traps with the possibility of billions of barrels of

hydrocarbons.

The DWRR Act also encouraged extensive leasing in the deepwater GOM. Figure 5

shows the recent history of deepwater leasing. Activity slowly increased from 1992

through 1995. Immediately after the DWRR Act was enacted, however, 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 evolvement of deepwater development

technology.) Deepwater leasing activity slowed somewhat in 1998 and 1999, possibly

because of low oil prices. Note also the gradual but continuous progression of leasing

into deeper waters with time. The GOM leasing status is shown in figure 6. Shallowwater leasing is especially dense. The deepwater is also heavily leased, but some voids

remain. There are about 3,930 active leases in water depths less than 1,000 ft, about
1992-1993 1994-1995

1996-1997 1998-1999

Figure 2. - Progressive deepwater 3-D seismic permit coverage from 1992 through 1999.

6
7

Figure 3. - Deepwater Gulf of Mexico 3-D seismic permit coverage from 1992 through 1999.
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Figure 4. - New deepwater plays in the Gulf of Mexico.

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MM99020

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Figure 5. - Deepwater leases issued in the Gulf of Mexico. MM99023

9
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Figure 6. - Active leases in the Gulf of Mexico.

50 0 50 100 Miles

Active Leases by Water Depth < 1,000 feet 1,000 - 1,499 feet 1,500 - 4,999 feet 5,000 - 7,500 feet >= 7,500 feet N

HG99012

10
11

180 active leases in 1,000-1,499 ft water depth, about 1,830 active leases in 1,500-

4,999 ft water depth, about 1,190 active leases in 5,000-7,499 ft water depth, and about

470 active leases in water depths of 7,500 ft and greater. The abrupt termination of active

leases south of the Alabama-Florida state line is where the Eastern Planning Area begins.

A lease sale in a portion of this planning area is scheduled to occur in 2001, the first

Eastern Gulf lease sale since 1988.

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

Figure 7 illustrates many natural features and manmade zones that require special

considerations for oil and gas activities. The Minerals Management Service (MMS) is

currently conducting an environmental assessment (EA) on deepwater oil and gas

activities; it will ensure that these activities occur in a technically safe and

environmentally sound manner. Furthermore, the EA will identify and evaluate potential

impacts from deepwater operations and develop potential measures to mitigate impacts

from deepwater activities on the marine, coastal, and human environments.

In addition to environmental considerations specific to deepwater, significant financial

obstacles exist. Deepwater operations are very expensive and often require significant

amounts of time between the initial exploration and first production. A further constraint

is the availability of drilling rigs capable of drilling deepwater wells (the number of ultradeepwater rigs is especially limited).

Despite these obstacles, deepwater operators often reap great rewards. Figure 8 shows

the history of discoveries in the Gulf of Mexico. There is a clear shift toward deeper

water with time, and the number of deepwater discoveries continues at a steady pace.

Note that the first frame of this figure represents a 10-year span, whereas the other frames

represent 5-year spans. Figure 9 shows how major and nonmajor oil and gas companies

compare in terms of deepwater discoveries. (Appendix B lists those companies defined

as majors.) Leases that were majority-owned by major companies (when the discoveries

occurred) are shown as black circles and leases majority-owned by nonmajor companies

are shown as open circles. To date, majors account for about two-thirds of the deepwater

discoveries. Additionally, discoveries by nonmajor companies tend to be in the shallower

portions of the deepwater, while majors tend to dominate the ultra-deep frontier areas

(at least to date).

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

deepwater wells and field sizes of deepwater discoveries are often quite large. These

factors are critical to the economic success of deepwater development. Figure 10

illustrates the estimated sizes and distributions of 39 proved deepwater fields. In addition

to their large sizes, deepwater fields have a wide geographic distribution and also range

in geologic age from Pleistocene through Miocene and older.

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

from onshore service bases. Producing deepwater fields have service bases in southeast

Louisiana (figure 11). Pending Plans of Exploration (POE’s) and Development

Operations Coordination Documents (DOCD’s) filed with MMS indicate that support
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%U %U%U%U %U%U %U%U%U %U

#

##

%U%U%U%U%U %U

%U##%U%U

TEXAS LOUISIANA MISSISSIPPI ALABAMA

East Breaks

Alaminos Canyon

Garden Banks

Keathley Canyon Lund

Lloyd Ridge

Henderson

De Soto Canyon

Mississippi Canyon

Destin Dome

Walker Ridge

Green Canyon Atwater Valley

7500 feet

5000 feet 1000 feet

1500 feet

HARBOR ISLAND

GALVESTON

CAMERON

GRAND CHENIER

MORGAN CITY

VENICE

GRAND ISLE

HOUMA

LEEVILLE

FOURCHON

Figure 12. - Onshore service bases for pending deepwater plans.

50 0 50 100 Miles N %U FOURCHON (50%) ÊÚ GALVESTON (20%) # Other (Cameron, Grand Chenier, Grand Isle, Harbor Island, Houma, Leeville, Morgan City and Venice) (30%)

MM99021

17
18

from southeast Louisiana will grow significantly, and new support will come from

southwest Louisiana and the Texas coast (figure 12). Although expanding along the Gulf

Coast, shore-based support for deepwater operations is likely to remain concentrated in

southeastern Louisiana.

The infrastructure needed to bring deepwater production online continues to develop over

time. Figure 13 shows the framework of major oil and gas pipelines in the shallow-water

GOM. Figure 14 illustrates the network of deepwater pipelines currently in place. The

deepwater pipeline infrastructure grew rapidly over the past few years to keep pace with

the expanding number of deepwater fields.
Figure 13. - Oil and gas pipelines with diameters greater than or equal to 20 inches.

25 0 25 50 Miles

N Pipelines with a diameter of at least 20 inches

HG99014

Alaminos Canyon Keathley Canyon Lund Walker Ridge

East Breaks Garden Banks Green Canyon

Mississippi Canyon

Atwater Valley

TEXAS

MISSISSIPPI

Garden Banks

Alaminos Canyon

LOUISIANA

5000 feet

7500 feet

1500 feet

1000 feet

19
Figure 14. - Deepwater oil and gas pipelines. HG99016

TEXAS

LOUISIANA

Atwater Valley Garden Banks

1500 feet

7500 feet

Viosca Knoll

Alaminos Canyon

Green Canyon

Mississippi Canyon

5000 feet

1000 feet

East Breaks

N

Oil Pipeline Gas Pipeline

20

25 0 25 50 Miles
21

Leasing 

Leasing activity in the deepwater GOM increased steadily in the early 1990’s and

exploded in 1996 because of, in part, the economic incentives introduced in the Deep

Water Royalty Relief (DWRR) Act. Figure 15 shows the magnitude of the DWRR

impact, with tremendous deepwater leasing activity from 1996 to 1998 in water depths

greater than 800 meters (where the greatest royalty relief is available). The boom in

deepwater leasing was also enhanced by the evolvement of deepwater technology, several

large deepwater discoveries, and excellent production rates coming from deepwater

fields.

The water depth categories depicted in figure 15 are based on the divisions used in

DWRR. This figure includes shallow- and deepwater leasing trends for an 8-year period.

Figure 16a was derived from the data in figure 15, but displays the deepwater categories

used elsewhere in this report (shallow-water data are excluded from figure 16a). These

deepwater data show the rapid increase in leasing activity that began in 1995 (primarily

in the 1,500-4,999 ft water depths) and exploded in 1996 (throughout the deepwater).

Figure 16b shows the total amount of money bid in each water depth range since 1992.

Large financial investments were made from 1996 through 1998, with sharp spending

increases in water depths greater than 5,000 ft. Figure 16c combines the data in figures

16a and 16b to reveal the average bid price of deepwater leases through time. The

average bid price for all deepwater leases steadily increased from 1994 through 1998,

particularly in water depths greater than 1,500 ft. In fact, the average bid price for ultradeepwater tracts (greater than or equal to 7,500 ft water depth) rose to levels comparable

with leases in less than 5,000 ft water. This is likely due to several discoveries in water

depths approaching 7,500 ft, very large structural traps in these areas, and the improved

feasibility of developing ultra-deepwater fields. Note that figures 16a-c reflect all blocks

that received bids (including those that were rejected).

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

increasing number of deepwater high bids that it viewed as insufficient (figure 17).

Apparent also in figure 17 is the fact that tracts with rejected bids moved into

increasingly deeper waters in the late 1990’s. From 1992 through 1995, almost all

rejected bids were on the shelf. In 1996-1997, bid rejects were evenly divided between

shallow- and deepwater. In 1998-1999, however, the majority of bid rejects were in

deepwater. This 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 deepwater sale blocks, leading to

the increased net present worth of many unleased blocks.

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 Arco, BP Amoco,

Chevron, Exxon Mobil, Shell, and Texaco. Appendix B breaks this list down further,

showing the companies and subsidiaries we combined to form these six majors. (Our

grouping of these six does not indicate a regulatory conclusion or an analysis of
        



 



      























 





















 

 













 

















  

0

200

400

600

800

1000

1200

Number of Leases

1992 1993 1994 1995 1996 1997 1998 1999

Year

< 200m

 2-400m

 4-800m

800m+

Figure 15. - Number of leases issued each year subdivided by DWRR water

 depth categories.

DWRR

22
0

600500400300200100

Number of Leases Bid 

1992 1993 1994 1995 1996 1997 1998 1999

Lease Year

1000-1499 ft.1500-4999 ft. 5000-7499 ft. >7500 ft. 

$0

$600,000,000$500,000,000$400,000,000$300,000,000$200,000,000$100,000,000

Bids

1992 1993 1994 1995 1996 1997 1998 1999

Lease Year

Figure 16b. - Total bid amounts in deepwater 

intervals.

1000-1499 ft.1500-4999 ft.5000-7499 ft. >7500 ft.

0

800000600000400000200000

18000001600000140000012000001000000

Average Bid Amount

1992 1993 1994 1995 1996 1997 1998 1999

Lease Year

Figure 16c. - Average bid amount per block in deepwater intervals.

1000-1499 ft.1500-4999 ft. 5000-7499 ft. >7500 ft. 

23
% %

%

%

%%

%

%

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LOUISIANA TEXAS

7500 feet

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TEXAS LOUISIANA

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7500 feet

TEXAS LOUISIANA

5000 feet

1000 feet

1500 feet

100 0 100 200 Miles

1992 - 1993

1998 - 1999 1996 - 19971994 - 1995

Figure 17. - Rejected shallow- and deepwater Gulf of Mexico bids.

N

TM99020

24
1000 feet

5000 feet 7500 feet

TEXAS LOUISIANA

FLORIDA

1500 feet

1992 - 1993

Majors: 403 leases

Nonmajors: 105 leases

1000 feet

5000 feet 7500 feet

TEXAS LOUISIANA

1500 feet

FLORIDA

1994 - 1995

Majors: 635 leases

Nonmajors: 186 leases

Figure 18. - Ownership of deepwater leases.

Leases with at least 50% major ownership

Leases with more than 50% nonmajor ownership 100 0 100 200 Miles

N

HG99008

25
1000 feet

7500 feet

5000 feet

TEXAS LOUISIANA

1500 feet

FLORIDA

1996 - 1997

Majors: 1,794 leases

Nonmajors: 812 leases

1000 feet

1500 feet

5000 feet 7500 feet

TEXAS LOUISIANA

FLORIDA

1998 - 1999

Majors: 2,436 leases

Nonmajors: 1,371 leases

N

Leases with at least 50% major ownership

Leases with more than 50% nonmajor ownership 100 0 100 200 Miles

Figure18. - - Ownership of deepwater leases. HG99009 continued

26
27

production size. It is merely a convenient category for the purpose of comparison.)

Figure 18 illustrates the relative lease-holding positions of majors versus nonmajors.

Leases with a majority ownership by majors are dark gray, and those majority-owned by

nonmajors are white with a black outline. Note that majors dominated deepwater leasing

in 1992 and 1993. In 1994 and 1995, majors still dominated leasing in the deepest

waters, leading the charge into this frontier. In 1996 nonmajors began acquiring

significant lease holdings, a trend that continued to grow through 1999.

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 recent wave of company mega-mergers. Figure 19 shows the impact on lease

holdings caused by several recent mergers and probable future mergers. These mergers

increase the diversity of lease holdings for the merged companies. For example, BP

focused heavily on the deepwater GOM, whereas Amoco was mixed between deep- and

shallow water, and Arco focused on shallow water. The potential combination of

companies yields a large GOM leasehold in all water depths and geographic areas. (As

of this writing, the BP Amoco merger with Arco is not yet approved.)

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

relinquished or expire will influence activity in future lease sales. Since most companies

can only drill a small percentage of their active leases, potentially high-quality leases

often expire without being tested. The turnover of these leases often results in re-leasing

at higher prices, “farm outs” to nonmajors, opportunities for nonmajors to gain a lease

position and, potentially, more rapid exploration and development of the acreage.

Figure 20 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 5 years in length for blocks

in less than 400 meters of water, 8 years in length for blocks in 400-799 meters of water,

and 10 years in length for blocks in 800 meters of water or greater. Therefore, in the

absence of primary lease term extensions, all currently active shallow water leases will

expire before 2005 (thus the sparse population and absence of expiring shallow water

leases in certain frames of figure 20). The upcoming lease sales in 2000 and 2001 will

offer a large number of expiring deepwater leases. The 2002 and 2003 lease sales will

offer only a handful of expiring deepwater leases because of depressed leasing activity in

1992 and 1993. Deepwater lease availability should increase again in 2004 and 2005

and, beginning in 2006, numerous deepwater leases will become available, this latter

resulting from the leasing boom that began in 1996. These lease expiration projections

will put pressure on leaseholders to drill and evaluate their holdings and provide

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

expire or obtaining “farm-outs” from companies with excess acreage.
7500 feet 5000 feet

LOUISIANA TEXAS

5000 feet 7500 feet

LOUISIANA TEXAS

7500 feet 5000 feet

LOUISIANA TEXAS

Kerr-McGee Oryx

TEXAS LOUISIANA

5000 feet 7500 feet

N 100 0 100 200 Miles

BP/Amoco/Arco

Mobil/Exxon Kerr-McGee/OryxBurlington/LL&E

Figure 19. - Leasing impact of recent company mergers and probable future mergers.

Arco Amoco BP Burlington LL&E

Exxon Mobil

TM99021

28
TEXAS LOUISIANA

5000 feet

7500 feet

1500 feet 1000 feet

2000 - 2001 (1,352 leases)

Figure 20. - Anticipated lease expirations in the Gulf of Mexico. 1000 feet

1500 feet

5000 feet

7500 feet

TEXAS LOUISIANA

2004 - 2005 (315 leases)

1500 feet

5000 feet

7500 feet

TEXAS LOUISIANA

1000 feet

2002 - 2003 (1,054 leases)

100 0 100 Miles

TM99022

29
7500 feet

5000 feet

TEXAS LOUISIANA

2008 - 2009 (841 leases) 1000 feet

1500 feet

TEXAS LOUISIANA

2006 - 2007 (1,744 leases)

Figure 20. - continued - Anticipated lease expirations in the Gulf of Mexico. TM99023

100 0 100 Miles

30
31

Drilling and Development 

Although there are numerous deepwater leases and prospects waiting to be drilled, there

are a limited number of deepwater drilling rigs available. Figure 21 shows the average

number of rigs drilling in the deepwater GOM since 1992. There has been a steady

increase in deepwater rig activity during this time, and the number of rigs drilling in the

deepwater GOM is expected to continue increasing slightly through 2001 (DeLuca, 1999;

Harding, 1999). Even with the increased number of deepwater rigs, only a small fraction

of the 3,670 active deepwater leases can be drilled before they expire.

Figure 22 shows the approximate number of deepwater GOM rigs and their water depth

capabilities. Currently, there are about 45 rigs in the GOM capable of drilling deepwater

wells (DeLuca, 1999; Harding, 1999; Kelly, 1999; Bollinger, 1999; Rig Census, 1999;

Gulf of Mexico Weekly Rig Locator, 1999). Five of these rigs can drill in water depths

up to 1,499 ft; about 22 rigs have a maximum water depth capacity between 1,500 and

4,999 ft; 14 rigs are capable of drilling in 5,000 to 7,499 ft of water; and only 4 GOM rigs

can drill in greater than or equal to 7,500 ft of water. The fact that the number of

available GOM rigs (figure 22) is slightly higher than the average number drilling

(figure 21) is not because of inactive deepwater rigs. It probably reflects rigs changing

locations and rigs drilling in water depths less than their maximum capabilities.

Currently, there are only four rigs in the GOM capable of drilling in water depths of

7,500 ft or greater and, thus, the evaluation of the 470 active leases in this water depth

range will be constrained. However, there are approximately 15 rigs under construction

that can drill in these ultra-deep waters (DeLuca, 1999; Harding, 1999; Rig Census, 1999;

Hart’s E&P Magazine, 1999; Bollinger, 1999; Kelly, 1999). There is a worldwide

demand for these ultra-deepwater rigs, and economics play a significant role in their

migration to and from oil regions. Several ultra-deepwater rigs have left the GOM in

favor of international locations (particularly West Africa), although other deepwater rigs

(with more limited water depth capabilities) have moved into the GOM. Unfortunately,

very few deepwater rigs are under construction for deliveries beyond 2000 (DeLuca,

1999).

Figure 23 illustrates a significant increase in the number of deepwater exploratory wells

drilled from 1992 through 1998, especially in the 1,500-4,999 ft water depth range.

Exploratory drilling in 1999 was down slightly from the record 1998 levels and, thus far,

there has been minimal drilling activity in water depths greater than 7,500 ft. Figure 25

illustrates the geographic distribution of deepwater exploratory wells. Note the

progression into the western GOM and into deeper water through time. (Note also that

we define exploratory wells as those numbered 1 thru 5. For example, the GC 136 No. 7

well is classified as exploratory, but we define it as a development well in this report

because it probably had a developmental objective.)

Figure 24 shows increased development drilling from 1992 through 1997. The vast

majority of development drilling was in the 1,500-4,999 ft water depth range. Note also

the diminished deepwater development drilling in 1998 and 1999. Figure 26 depicts the
3

6

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26 28 27

30 31

0

5

10

15

20

25

30

35

Average Number of Rigs Drilling

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Year

Figure 21. - Average number of rigs drilling in the deepwater Gulf of Mexico.

5

22

14

4

0

5

10

15

20

25

Number of Rigs with this Maximum Capability

1000-1499 1500-4999 5000-7499 7500+

Maximum Water Depth Capability (ft)

Figure 22. - Approximate number of deepwater Gulf of Mexico rigs subdivided

 according to their maximum water depth capabilities.

32
0

20

40

60

80

100

120

Number of wells spudded

1992 1993 1994 1995 1996 1997 1998 1999

Year

1,000-1,499'

1,500-4,999'

5,000-7,499'

7,500'+

Figure 23. - Deepwater exploratory wells drilled in the Gulf of Mexico,

 subdivided by water depth.

0

20

40

60

80

100

120

Number of wells spudded

1992 1993 1994 1995 1996 1997 1998 1999

Year

1,000-1,499'

1,500-4,999'

5,000-7,499'

7,500'+

Figure 24. - Deepwater development wells drilled in the Gulf of Mexico,

 subdivided by water depth.

33
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1992 - 1993

100 0 100 200 Miles

1998 - 1999 1996 - 19971994 - 1995

Figure 25. - Deepwater exploratory wells drilled in the Gulf of Mexico.

(18 wells)

(119 wells)

(61 wells)

(200 wells)

MM99024

34
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1992 - 1993

100 0 100 200 Miles

1998 - 1999 1996 - 19971994 - 1995

Figure 26. - Deepwater development wells drilled in the Gulf of Mexico.

(58 wells)

(169 wells)

(87 wells)

(142 wells)

MM99025

35
36

locations of these development wells. Once again the data reveal a general increase in

activity with time as well as a trend toward increasing water depth with time.

When deepwater exploratory and development drilling are combined, it becomes clear

that deepwater drilling increased rapidly from 1992 to 1997, but remained flat from 1997

through 1999. That is, 170 to 175 deepwater wells were drilled each year (from 1997

through 1999), even though the focus shifted between exploration and development. This

trend mirrors the deepwater rig activity (figure 21), as expected.

Other indicators of deepwater activity include the number of plans received and approved

by MMS. Although the order of plan submission and drilling activities can vary with

projects, operators generally proceed as follows:

• file a Plan of Exploration (POE),

• drill exploratory wells,

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

• file a Development Operations Coordination Document (DOCD),

• drill development wells,

• file a preliminary DWOP,

• file a final DWOP, then

• begin production.

Figure 27 shows the number of deepwater POE’s, deepwater DOCD’s, and DWOP’s

received each year since 1992 (DWOP’s were not required until 1995). Some shallowwater activities are included in the DWOP data because DWOP’s must be filed and

approved for developments in greater than 1,000-ft water depths and all subsea

developments regardless of water depth. Further, figure 27 shows the years when the

initial (conceptual) DWOP’s were filed for each project.

There was a sharp increase in deepwater exploratory plan approvals from 1992 through

1999. The number of deepwater development plan approvals also showed a general

increase during this time. The number of DWOP’s filed was relatively constant from

1996 through 1999, with the exception of 1997. Recall that 1997 was also a year when

an exceptionally high number of development wells were drilled (figure 24).

Figures 28 and 29 show the progression of GOM drilling toward deeper wells and greater

water depths. Figure 28 shows the maximum true vertical depth (TVD) of wells drilled

each year since 1947 (when drilling in the Gulf of Mexico OCS began). Clearly, there

was a gradual increase in maximum TVD from 13,636 ft in 1948 to 26,978 ft in 1998.

Figure 29 shows the maximum water depth drilled each year since 1947. Deepwater

drilling began in 1974 (1,024 ft), followed by significant water depth milestones in 1976

(1,986 ft), 1984 (3,534 ft), and 1987 (7,500 ft). The current record (7,716 ft) is likely to

be eclipsed soon; an operator filed plans to drill in over 9,600 ft of water by yearend

2000. Unlike the gradual progression of TVD through time, the progression into deep

water was very rapid.
Figure 27. - Deepwater POE’s approved, deepwater DOCD’s approved, and

 DWOP’s received in the Gulf of Mexico since 1992.

37

24

3

21

3

33

4

34

8 5

62

4

19

85

13

30

124

13 16

143

16

18

0

20

40

60

80

100

120

140

160

Number of Plans

1992 1993 1994 1995 1996 1997 1998 1999

Year

Deepwater POE's

Deepwater DOCD's

DWOP's
0

5000

10000

15000

20000

25000

30000

Maximum Well TVD (feet) 

19471952195719621967197219771982198719921997

Year

Figure 28. - Maximum wellbore true vertical depth (TVD)

 drilled each year.

0

1000

2000

3000

4000

5000

6000

7000

8000

Maximum Water Depth (feet)

19471952195719621967197219771982198719921997

Year

Figure 29. - Maximum water depth drilled each year.

38
39

There are several development systems capable of producing deepwater oil and gas.

Figure 30 illustrates several systems that are currently available and table 1 lists the

systems used to develop productive deepwater GOM fields. Fixed platforms

(e.g., Cognac) have economic water depth limits of about 1,200 to 1,500 ft. Compliant

towers (e.g., Baldpate) may be considered for water depths of approximately 1,000 to

3,000 ft. Tension leg platforms (TLP’s) and mini-TLP’s (e.g., Auger and Morpeth,

respectively) are frequently used in 1,000 to 5,000-ft water depths. Spars (e.g., Genesis)

and other floating production systems may be used in 8,000-ft water depths and beyond.

Subsea systems (e.g., Mensa) are also capable of producing hydrocarbons from reservoirs

in excess of 8,000-ft water depths. Though no floating, storage, production, and

offloading system (FPSO) has been installed in the Gulf of Mexico, strong interest has

been expressed by several companies to use this type of production facility. Water depth

ranges expected for FPSO’s range from 1,000 to greater than 8,000 ft.

The FPSO technology and shuttle tankering of OCS crude oil present many new

operational options and questions. The FPSO systems can be used as crude processing

facilities or for storing large volumes of crude oil (1 million barrels or more) in the hull

prior to offloading and tankering to shore. The MMS is preparing an environmental

impact statement (EIS) to assess the potential impacts of FPSO operations and associated

support activities within the Central and Western Planning Areas of the GOM. A

contract to prepare the EIS was awarded to Ecology and Environment, Inc. in April 1999.

It is anticipated that completion of the EIS will occur in late 2000. The MMS’s

objectives in preparing the EIS are listed below.

• To ensure that FPSO operations and associated support operations conducted in

the deepwater Gulf of Mexico OCS occur in a technically safe and

environmentally sound manner;

• To describe the types and ranges of potential FPSO operations and associated

support activities;

• To determine reasonable alternatives to specific aspects of proposed FPSO

operations;

• To identify potential impacts from FPSO operations and associated support

activities on the marine, coastal, and human environments;

• To evaluate the significance of potential impacts from FPSO operations and

associated support activities;

• To develop appropriate measures to mitigate potentially significant impacts from

FPSO operations and associated support activities; and

• To provide a National Environmental Policy Act (NEPA) summary document that

will support future NEPA assessments of FPSO operations and associated support

activities.

Subsea systems are a key component to the recent increase in deepwater activity. These

systems are generally multicomponent seafloor facilities that allow for the production of

hydrocarbons in water depths that would normally preclude installing conventional fixed

or bottom-founded platforms. Through an array of subsea wells, manifolds, central

umbilicals, and flowlines, a subsea system can be located many miles away in deeper
Figure 30. - Deepwater development systems.

40
41

Table 1. - Development Systems of Productive Deepwater GOM Fields.

Year of First

Production System Type Field Nickname Block Water Depth Operator

1979 Fixed Platform Cognac MC 194 1,023 ft Shell Offshore Inc.

1984 Compliant Tower Lena MC 281 1,017 ft Exxon

 1988* FPS Unnamed GC 75 2,172 ft Oryx

 1988* Semi-Submersible Unnamed GC 29 1,554 ft Placid

1989 Fixed Platform Bullwinkle GC 65 1,330 ft Shell Offshore Inc.

1989 TLP Jolliet GC 184 1,722 ft Conoco

1991 Fixed Platform AmberJack MC 109 1,058 ft BP Amoco

 1993* Subsea Diamond MC 445 2,095 ft Oryx

 1993* FPS/Subsea Seattle Slew EW 914 1,019 ft Tatham

1993 Subsea Zinc MC 354 1,478 ft Exxon

1994 Fixed Platform/Subsea Pompano/Pompano II VK 990 1,445 ft BP Amoco

1994 Subsea Tahoe/Tahoe II VK 783 1,492 ft Shell Deepwater Prod. Inc.

1994 TLP Auger GB 426 2,864 ft Shell Deepwater Prod. Inc.

 1995* Semi-Submersible Cooper GB 387 2,163 ft EEX

1995 Subsea Unnamed VK 862 1,043 ft Walter Oil & Gas

1996 Subsea Popeye GC 116 2,067 ft Shell Deepwater Prod. Inc.

1996 Subsea Rocky GC 110 1,621 ft Shell Deepwater Prod. Inc.

1996 TLP/Subsea Mars MC 807 2,958 ft Shell Deepwater Prod. Inc.

1997 Spar Neptune/Thor VK 825 1,866 ft Kerr-McGee

1997 Subsea Mensa MC 731 5,330 ft Shell Deepwater Prod. Inc.

1997 Subsea Troika GC 244 2,681 ft BP Amoco

1997 TLP Ram Powell VK 956 3,247 ft Shell Deepwater Prod. Inc.

1998 Compliant Tower Baldpate GB 260 1,605 ft Amerada Hess

1998 Mini-TLP/Subsea Morpeth/Klamath EW 921 1,706 ft British-Borneo

1998 Subsea Salsa GB 171 1,074 ft Shell Offshore Inc.

1998 Subsea Arnold EW 963 1,752 ft Marathon

1999 Mini-TLP/Subsea Allegheny GC 254 3,186 ft British-Borneo

1999 Spar Genesis GC 205 2,599 ft Chevron

1999 TLP Ursa MC 810 3,885 ft Shell Deepwater Prod. Inc.

1999 Subsea Angus GC 112 1,465 ft Shell Deepwater Dev. Inc.

1999 Subsea Dulcimer GB 367 1,124 ft Mariner

1999 Subsea Gemini MC 292 3,745 ft Texaco

1999 Subsea Macaroni GB 602 3,600 ft Shell Deepwater Dev. Inc.

1999 Subsea Unnamed EW 1006 1,832 ft Walter Oil & Gas

1999 Fixed Platform Virgo VK 823 1,154 ft Elf

* Indicates fields that are no longer on production.
42

water and tied back to existing “host” facilities in shallow water. Figure 31 shows the

number of subsea completions each year since 1955 (only productive wells were

counted). There were fewer than five subsea completions per year until 1989. This

number increased dramatically throughout the 1990’s.

The technology required to implement subsea production systems in deepwater evolved

significantly in the last decade. This evolution is apparent in figure 32, which shows the

deepest subsea completion was in 350 ft of water until 1988, when the water depth record

jumped to 2,243 ft (GC 75 field). In 1996 another milestone was reached with a subsea

completion in 2,956 ft of water (Mars field), followed by a 1997 subsea completion in

5,295 ft of water (Mensa field). A listing of productive subsea completions in the GOM

OCS can be found in Appendix C.

According to MMS records, there is a total of 186 subsea completions to date, 83 of

which (45%) were completed in the four years 1996-1999. Of the 186 subsea

completions, 62 of these (33%) were in deepwater and 40 (65%) of these deepwater

subsea completions occurred from 1996 through 1999. Figure 33 shows that the number

of deepwater subsea completions increased steadily from 1994 through 1999, with

anomalously high numbers of deepwater completions in 1993 and 1996. The use of

subsea completions in shallow water also increased rapidly from 1992 through 1997.

There was a significant drop in the number of shallow-water subsea completions in 1998,

possibly related to low oil prices.

The distance from subsea completions to their host facilities varies considerably.

Figure 34 shows the lengths of deepwater flowlines that are 4 to 12 inches in diameter

and carry bulk oil or gas (pipeline segments less than 1,000 ft long are excluded). The

majority of these flowlines are less than 15 miles long. A few tiebacks are 20 to

30 miles, and Shell’s Mensa field is a record 62 miles from its host facility in West Delta

Block 143. Most of these pipelines were approved after 1992, but there is no clear

relationship between approval date and length of tieback.

The pipeline infrastructure to bring deepwater oil and gas onshore also expanded during

the 1990’s. Figures 35a and 35b show a significant increase in the mileage of deepwater

pipelines approved the past few years. A significant portion of this increase involved

pipelines less than or equal to 12 inches in diameter (figure 35a), and an exponential

increase occurred in the mileage of large (greater than 12 inches in diameter) deepwater

oil and gas pipelines laid over the past 3 years (figure 35b).
Figure 31. - Number of subsea completions each year.

Figure 32. - Maximum water depths of subsea completions each year.

0

5

10

15

20

25

Number of Subsea Completions

195519601965197019751980198519901995

Year

0

1000

2000

3000

4000

5000

6000

Maximum Water Depth (ft)

195519601965197019751980198519901995

Year

Mars

Mensa

GC 75

HI A573

43
44

1

2

3

11

7

1

10

4

12

10

13

7

8

9

10

14

0

4

8

12

16

Number of Subsea Completions

1992 1993 1994 1995 1996 1997 1998 1999

Year

Shallow Water

Deep Water

Figure 33. - Number of shallow- and deepwater subsea completions

 each year since 1992.

16

12

18

2 2

1

0

5

10

15

20

Number of Pipeline Segments

0.2 - 4 5 - 9 10 - 14 15 - 19 20 - 24 25 - 29 30+

Length of Pipeline Segment (mi.)

Figure 34. - Length of subsea tiebacks.
Figure 35. - Deepwater oil and gas pipelines (a) less than or equal to 12 inches

 in diameter and (b) greater than 12 inches in diameter.

0

50

100

150

200

250

300

350

Miles of Pipelines Approved

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

Year

Gas

Oil

0

50

100

150

200

250

300

350

Miles of Pipelines Approved

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

Year

Gas

Oil

(a)

(b)

45
46

Reserves and Production 

The deepwater GOM has contributed major additions to the total region’s reserves.

Figure 36a 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.

There is often a significant time lag between a successful exploratory well and its

hydrocarbons reaching proved status (in a producing or soon to be producing field). The

success of an exploratory well may remain concealed from the public for several years

until an 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 by MMS. 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 36b

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

shows declining reserve additions in shallow water similar to figure 36a, but reveals

significantly more deepwater reserve additions.

The most important feature of the deepwater field discoveries is observed in figure 36c,

where the average size of deepwater fields is many times larger than the average size of

shallow-water fields. During the 1990’s the average shallow-water field added

approximately 5 MMBOE of proved and unproved reserves. In contrast, the average

deepwater field during this same period added over 47 MMBOE of proved and unproved

reserves (over 9 times more than shallow water). In the most active deepwater

exploration area, water depths between 1,500 and 7,499 ft, the average deepwater field

contributed over 60 MMBOE (12 times more than the average shallow-water field

addition). This is typical of frontier areas and indicates that there are many large

deepwater fields yet to be discovered.

Figure 37 shows the number of deepwater fields discovered each year, according to MMS

criteria, since 1975. (See appendix A for a listing of deepwater fields 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 climbs in the late 1990’s, since

these recent field discoveries have had little time to reach production. Because of this

time lag between exploratory drilling and first production, the true impact of recent, large

deepwater exploratory successes are not yet reflected in MMS proved and unproved

reserve estimates.

In an attempt to capture the impact these successful deepwater exploratory successes,

figure 38 adds MMS known resource estimates and several industry-announced

discoveries to the proved and unproved reserve volumes. The industry-announced

discovery volumes contain considerable uncertainty, are based on limited drilling, include
                         

  

    

  



 



 



   

  

  

  



 



 



 

    

        

    

        



 



 

  

   

    

  

          

      

  



    

    

        

              

3,00 0,00 0,00 02,50 0,00 0,00 02,00 0,00 0,00 01,50 0,00 0,00 01,00 0,00 0,00 050 0,00 0,0000

7500+

5000-7499

1500-4999

1000-1499

0-999

7500+  5000-7499

 1500-4999

1000-1499

 0-999

                     

  

    



 

 

             

                  

     

     

       

 

  

 

  

 

  

  

  

  

     

 

     

                                         

3,0 00,00 0,00 02,5 00,00 0,00 02,0 00,00 0,00 01,5 00,00 0,00 01,0 00,00 0,00 050 0,00 0,00 00

7500+

5000-7500

1500-4999

0-999 1000-1499

Figure 36a. - Proved reserve additions

7500+

 5000-7500  1500-4999

1000-1499

 0-999 

Water Depth Interval (ft.)

Water Depth Interval (ft.)

47
     

  

 

  



    

   

  

  



 

   

  



 

  



 

  

  



  

  



 

  

  



 

     



 

    

       



 

    



 



  

     



    

  



 

    

    



     

     

       



 

    



       

     



 

           

      



 



 

    



 

4 00 ,0 0 0,0 0 03 50 ,0 0 0,0 0 03 00 ,0 0 0,0 0 02 50 ,0 0 0,0 0 02 00 ,0 0 0,0 0 01 50 ,0 0 0,0 0 01 00 ,0 0 0,0 0 05 0,0 0 0 ,00 0-

7500+

5000-7499

1500-4999

0-9991000-1499

7500+

 5000-7499  1500-4999

1000-1499

 0-999

Field Discovery Year

BOE

Water Depth Intervals (ft.)

48

Figure 36c. - Average field size using proved and unproved reserves.
Figure 37. - Number of deepwater field discoveries and resulting number of producing fields.

86420

141210

1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999

Field Discovery Year

Number of Fields

Number of DiscoveriesNumber that are Producing

3

1

3

1

12

7

6

8

5

7

4 4

1

4

5

7 7

9

11

1

3

0

800,000,000600,000,000400,000,000200,000,000

1,200,000,0001,000,000,000

1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999

Field Discovery Year

BOE

14121086420

 Fields Disc. or Anncd.

Proved Reserves in BOEUnprvd, Resc. & Indust Anncd. Disc.Number of Discoveries

49
50

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. In figure 38, the apparent decline of proved reserve additions in recent years is

caused by the previously mentioned developmental time lag.

The inclusion of the very large, recent, industry-announced deepwater discoveries with

MMS resource estimates illustrates that successful deepwater exploration is adding

significant volumes to total GOM hydrocarbon reserves. These large additions show the

excellent potential for continued future growth in deepwater activity levels and deepwater

reserves. Figure 39 illustrates the distribution of new hydrocarbon additions in the GOM

categorized by water depth. When compared with figures 36a (proved reserves) and 36b

(proved and unproved reserves), figure 39 (proved reserves, unproved reserves, known

resources, and industry-announced reserves) shows that recently announced industry

discoveries will add significant reserves to the GOM if industry estimates are accurate.

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 40

illustrates the relative volume of production from each GOM lease through time. Notice

the large deepwater volumes, which appear in 1998 and 1999. Lagging slightly behind

the boom in exploratory activity, deepwater production is emerging quickly and

impressively.

Figure 41a illustrates historic trends in oil production (Melancon and Baud, 2000).

Shallow-water oil production has been relatively flat to slightly declining, but deepwater

oil production increased dramatically. In late 1999, deepwater GOM oil surpassed

shallow-water production for the first time in history. This strong increase in deepwater

oil production more than offsets recent declines in shallow-water oil production. Figure

41b shows similar production trends for gas. Shallow-water gas production was

relatively stable over the past 15 years, with a slight recent decline. The steady increase

in deepwater gas production that occurred in the past few years offset the shallow-water

decline. Deepwater oil and gas production is expected to continue increasing through at

least 2002 (Melancon and Baud, 2000).

A significant portion of deepwater production comes from subsea completions.

Figure 42a shows that very little deepwater oil production came from subsea completions

until mid-1995. By the fall of 1996, about 20 percent of deepwater oil production came

from subsea completions. There was a slight decline in deepwater oil production from

subsea completions in 1997, but increasing production since that time. Deepwater gas

production from subsea completions (figure 42b) shows a similar trend. No deepwater

gas production came from subsea completions in early 1993, but subsea completions

accounted for over 40 percent of deepwater GOM gas production by mid-1994. There

was a slight decline in deepwater gas production from subsea completions in 1995, but

increasing production since that time. Subsea completions currently account for about

25 percent of deepwater oil production and about 40 percent of deepwater gas production.
 

 

  

    

  

  

    



 

  



 

   



 

     



 

      

 

 

   

      



 

    



  

      



  

     



  

         

 

  

                 



 

                      



 

      



 

          



 

       



 

  



 

    



 

     

    



  

            



  

     



 

       

  



 

          



       



 

  

3,000,000,0002,500,000,0002,000,000,0001 ,500,000,0001 ,000,000,000500,000,000-

1 965 1 967 1 969 1 971 1 973 1 975 1 977 1 979 1 981 1 983 1 985 1 987 1 989 1 991 1 993 1 995 1 997 1 999

7500+

5000-7499

1 500-4999

0-9991 000-1 499

Field Discovery Year

Fi

39

BOE 

dd

d (

k

d i

d

t

d di

i

)

51

Water depth intervals (ft.)
Water Depth N

< 1,000 ft

> 1,000 ft

Figure 40. Relative volume of production from each Gulf of Mexico lease. Bar heights are proportional to total lease production (barrels of oil equivalent) during that time interval.

MM99018

52

1992 - 1993

1994 - 1995
1998 - 1999

1996 - 1997

Water Depth N

< 1,000 ft

> 1,000 ft

Figure 40. - continued - Relative volume of production from each Gulf of Mexico lease. Bar heights are proportional to total lease production (barrels of oil equivalent) during that time interval. continued MM99018

53
54

0

200,000

400,000

600,000

800,000

1,000,000

1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

Year

Deepwater oil

Shallow wtr oil

(a)

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

Year

Deepwater gas

Shallow wtr gas

(b)

Figure 41. - Comparison of yearend shallow- and deepwater (a) oil production

 and (b) gas production.

Barrels of Oil Per Day

Billion Cubic Feet of Gas Per Day
0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

Barrels of Oil/Day

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99

Date

Deepwater subsea completions

Total Deepwater Oil

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

Thousand Cubic Feet of Gas/Day

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99

Date

Deepwater subsea completions

Total Deepwater Gas

55

(b)

(a)

Figure 42. - Contributions from subsea completions toward total deepwater

 (a) oil production and (b) gas production.
56

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

companies through 1996 (figures 43a and 43b). (Production volumes in figures 43a-b

and 44a-b are attributed to companies on the basis of their percentage of lease ownership.

For example, if Shell owned 75% of a particular lease in July 1997, then 75% of that

lease’s production was attributed to Shell that month.) In recent years, nonmajor

companies significantly increased their deepwater oil production. Figures 44a and 44b

show that nonmajor oil and gas companies contributed about 15 percent of deepwater oil

production from 1992 through 1997. Nonmajor companies increased their share of

deepwater oil production in 1998 and early 1999. On the contrary, nonmajor companies

accounted for about 40 percent of deepwater gas production in early 1994. This

percentage declined steadily until 1998 (primarily due to Shell’s increased deepwater gas

production). Nonmajor companies currently own about 25 percent of deepwater GOM

oil production and about 20 percent of deepwater GOM gas production. Since there are

significant lag times between leasing and production, and nonmajors did not gain a

leasing foothold until about 1996 (figure 18), a surge of production from nonmajors could

still be forthcoming.

Figures 45a and 45b display production contributions from each major oil and gas

company. Shell and BP Amoco 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 has continued throughout

the 1990’s. Shell’s dominance in deepwater gas production began in the mid-1990’s, and

dramatically increased in 1997. Although BP Amoco’s deepwater oil production started

slightly behind Shell’s, their oil production increases track one another throughout the

1990’s (in part because Shell and BP Amoco have joint ownership in several large

deepwater fields). Exxon Mobil currently runs a distant third in terms of deepwater

GOM oil production, but is slightly ahead of BP Amoco in deepwater GOM gas

production.

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

operations. Figure 46a illustrates the highest deepwater oil production rates each month

since 1992. (Production rates in this report are daily averages from a full month of

production.) For example, a well within Shell’s Bullwinkle field produced about 5,000

barrels of oil per day (BOPD) in 1992. In 1994 a well within Shell’s Auger field set a

milestone, producing about 10,000 BOPD. Since 1994, maximum deepwater oil

production rates continued to climb, especially in water depths between 1,500 and

4,999 ft. Note that there is currently no production in water depths greater than or equal

to 7,500 ft and only minimal liquid production in water depths greater than or equal to

5,000 ft (from Shell’s Mensa field, which primarily produces gas). Figure 46b shows

similar production rates for gas. Maximum deepwater gas production rates hovered

around 25 million cubic feet per day (MMCFPD) until a well in Shell’s Popeye field

bumped the deepwater production record to over 100 MMCFPD in 1996. Since then, the

deeper waters yielded higher maximum production rates. In 1997, Shell’s Mensa field

showed the excellent potential for ultra-deepwater production rates. Note that the steep

fluctuations in production rates within the 5,000-7,499 ft water depth category probably

relate to the limited number of wells producing in this water depth range. That is, when
0

100,000

200,000

300,000

400,000

500,000

Dec-90Dec-91Dec-92Dec-93Dec-94Dec-95Dec-96Dec-97Dec-98Dec-99

Date

Barrels of Oil/Day

0

400,000

800,000

1,200,000

1,600,000

2,000,000

Dec-90Dec-91Dec-92Dec-93Dec-94Dec-95Dec-96Dec-97Dec-98Dec-99

Date

Thousand Cubic Feet of Gas/Day

Figure 43. - Comparison of major companies and nonmajor companies in

 terms of deepwater (a) oil production and (b) gas production.

(b)

(a)

Majors

Nonmajors

Majors

Nonmajors

57
0.0

5.0

10.0

15.0

20.0

25.0

30.0

Percentage

Jan-92Jan-93Jan-94Jan-95Jan-96Jan-97Jan-98Jan-99

Date

0.0

10.0

20.0

30.0

40.0

50.0

Percentage

Jan-92Jan-93Jan-94Jan-95Jan-96Jan-97Jan-98Jan-99

Date

(a)

(b)

Figure 44. - Percentage of deepwater (a) oil production and (b) gas

 production from nonmajor oil and gas companies.

58
0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

Dec-91 Dec-92 Dec-93 Dec-94 Dec-95 Dec-96 Dec-97 Dec-98 Dec-99

Date

Thousand Cubic Feet of Gas/Day

Shell

Exxon-Mobil

BP-Amoco Texaco Chevron Arco

0

50,000

100,000

150,000

200,000

250,000

Dec-91 Dec-92 Dec-93 Dec-94 Dec-95 Dec-96 Dec-97 Dec-98 Dec-99

Date

Barrels of Oil/Day

Shell

BP-Amoco

Exxon-Mobil

Texaco

Chevron

Arco

Figure 45. - Contributions from each major oil company toward total

 deepwater (a) oil production and (b) gas production.

(b)

(a)

59
0

50,000

100,000

150,000

200,000

250,000

Dec-90 Dec-91 Dec-92 Dec-93 Dec-94 Dec-95 Dec-96 Dec-97 Dec-98 Dec-99

Date

Thousand Cubic Feet Gas/Day

Figure 46. - Maximum production rates for a single well within each water depth

 category for deepwater (a) oil production and (b) gas production.

0

10,000

20,000

30,000

40,000

Dec-90 Dec-91 Dec-92 Dec-93 Dec-94 Dec-95 Dec-96 Dec-97 Dec-98 Dec-99

Date

Barrels of Oil/Day

(a)

(b)

1,000-1,499’

5,000-7,499’

Bullwinkle

Auger

Mars

Troika

1,500-4,999’

Ursa

Bullwinkle

Auger

Popeye

Mensa

5,000-7,499’

1,500-4,999’

1,000-1,499’

60
61

the only well on production is shut in for a short period of time, there are no other wells

to become the maximum producer during the lull. Since the third Mensa well

commenced production in late 1998, the maximum production rates in the 5,000-7,499 ft

water depth range have stabilized at approximately 90 MMCFPD. To date, the daily oil

production rate record for a single well is 36,520 BOPD (Ursa) and the record gas

production rate is 196 MMCFPD (Mensa).

Figures 47 (oil) and 48 (gas) compare maximum historical production rates for each lease

in the GOM. That is, the well with the highest historical production rate is shown for

each lease. These maps show that many deepwater fields produce at higher rates than

ever encountered in the GOM. Figure 47 also shows that maximum oil rates were

significantly higher off the southeast Louisiana coast than off the Texas coast. This trend

may change when Exxon’s Hoover and Diana fields begin production. Figure 48

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).

Figures 49 (oil) and 50 (gas) depict the recent emergence of high deepwater production

rates. Figure 49 shows the maximum oil production rates for all leases that produced

over 5,000 BOPD. In 1996-1997 high oil production rates from deepwater wells began

and immediately dominated the picture. Similarly, figure 50 shows the maximum gas

production rates for all leases that produced over 75 MMCFPD. The significance of

deepwater gas production rates began in 1996-1997 and continued through the present.
37,000

8,0003,000

Maximum Oil Rate (barrels per day) 16,000

Figure 47. - Maximum historical oil production rates for Gulf of Mexico wells. TM99026

LOUISIANA

TEXAS

MISSISSIPPI ALABAMA

Auger

SS182 Mars

Ram-Powell

Ursa

Troika

0

-1000 -1500 -5000-7500

Water depth (feet)

62
Figure 48. - Maximum historical gas production rates for Gulf of Mexico wells.

LOUISIANA

TEXAS

MISSISSIPPI

200,000

80,00040,000

Maximum Gas Rate (MCF per day)

ALABAMA

120,000

TM99025

WC580EC334 SM40

Auger

SS239 Popeye

MO823

MO869

Tahoe

Mars

Mensa

160,000

0 Water depth (feet)

-1000-1500-5000-7500

63
37,000

16,000

8,0003,000

Figure 49. - Maximum oil production rates for Gulf of Mexico wells that produced over 5,000 BOPD. 

1992 - 1993

TM99027

Maximum Oil Rate (barrels per day) Water depth (feet) 0 -1000 -1500

-5000-7500

1994 - 1995

1996 - 1997 1998 - 1999

64
200,000

160,000

80,00040,000

Figure 50. - Maximum gas production rates for Gulf of Mexico wells that produced over 75,000 MCFPD. 

1992 - 1993

TM99028

Maximum Gas Rate (MCF per day) Water depth (feet) 0 -1000 -1500

-5000-7500

120,000

1994 - 1995

1996 - 1997 1998 - 1999

65
66

Summary and Conclusions 

Thus far we discussed

• the emerging importance of the deepwater to overall Gulf of Mexico (GOM) oil

and gas production,

• the historical trend in deepwater leasing toward increasing water depths and

increased bid values,

• deepwater lease holdings of major oil and gas companies compared with

nonmajor companies, showing the increased presence of nonmajor companies,

• the impact of recent company mergers on deepwater lease holdings,

• future deepwater lease availabilities and anticipated lease expirations,

• rapid increases in deepwater rig activity from 1992 through 1997, followed by

modest increases since 1997,

• historical drilling statistics indicating significant increases in deepwater drilling

activity and rapid leaps toward deeper waters,

• the increase in deepwater development activity, especially in regard to subsea

completions,

• the progress of deepwater infrastructure development, especially pipelines

reaching into deepwater in the Garden Banks Area and the entire Central Planning

Area,

• the anticipated large deepwater reserve additions, especially when unproved

reserves, known resources, and recent industry-announced discoveries are all

taken into account,

• the large increase in average deepwater field sizes when compared with sameyear shallow-water discoveries,

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

production (Deepwater oil production recently surpassed shallow-water

production for the first time in GOM history.),

• deepwater production from various companies, showing increasing production

from majors and nonmajors, and historical domination by Shell and BP Amoco,

and

• very high deepwater production rates compared with shallow-water production

rates.

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

and production data, revealing overall trends in deepwater activity and expectations.

Figure 51 illustrates deepwater projects that began production in 1999 and those expected

to commence production soon (modified from Melancon and Baud, 2000). Nine

deepwater projects began production in 1999, the largest single-year increase in history.

Many more are expected in the next few years (several are not shown in figure 51

because operators requested that the information remain confidential).

Deepwater leasing activity accelerated in the late 1990’s after Congress enacted the Deep

Water Royalty Relief Act. The full effect of this leasing, however, will not be
#

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#

#

#

#

#

#

#

# #

#

#

#

#

#

$

#

#

$ #

# # # # #

#

$

$ $ $$

$

$

$ $

$

$

$ $

$

$

$ $

$

Mississippi Canyon

ANGUS BLACK WIDOW

NORTH GEMINI

EW1006 EL TORO

MARLIN VIRGO

GEMINI

URSA

PLUTO

ALLEGHENY GENESIS

MACARONI

DULCIMER

KING EAST ANSTEY

SERRANO

7500 feet

5000 feet

LOUISIANA

TEXAS

MISSISSIPPI ALABAMA FLORIDA

1500 feet 1000 feet

EUROPA

TYPHOON

KEPLER

ARIEL

MICA

KING KONG

HOOVER DIANA

FOURIER HERSCHEL

NILE

BRUTUS

$PETRONIUS

Alaminos Canyon

Garden Banks Atwater Valley

Destin Dome

De Soto Canyon

Green Canyon Garden Banks East Breaks

Alaminos Canyon Walker Ridge Henderson Lund Keathley Canyon

Lloyd Ridge

Figure 51. - Deepwater projects that began production in 1999 and those expected to begin production by yearend 2004.

50 0 50 100 Miles N Online 1999 Online 2000-2004 #$

TM99024

67
68

realized for several years because there can be considerable lag times between leasing

and first production, as illustrated in figure 52. There was considerable lease activity in

the late 1980’s. (Note that historic deepwater leasing shows no clear relation to average

oil prices.) Acreage at Auger (Garden Banks 426 field) and Neptune (Atwater 575 field)

were acquired in 1985 as part of this early activity. The first Auger well was drilled soon

afterward, in 1987. Even though Auger was leased and drilled early, the first production

didn’t begin until 1994, about 10 years after the initial lease acquisition. The first

Neptune well was not drilled until 1995, almost 10 years after the initial lease acquisition

and no first production date has been made public. These time lags are not unusual with

deepwater operations because of large lease inventories, the geologic and production

uncertainties of frontier discoveries, the limited number of deepwater rigs, and the

evolving deepwater development technology.

Figures 53a-c demonstrate average time lags associated with deepwater operations.

These figures use data only from deepwater leases that have become productive.

Figure 53a shows the average number of years it took to drill a well from the time the

lease was issued. Figure 53b shows the average length of time from lease issue to

qualification of the lease as productive (operators request that MMS qualify a lease as

capable of production after drilling a discovery well and before beginning production).

Figure 53c illustrates the time lags between leasing, qualification, and first production.

Figure 53d uses a slightly different population; it plots the time lag for all leases drilled,

all leases that qualified, and then leases that are productive. Obviously, there is a

declining number of leases in each succeeding category in figure 53d because the number

of leases drilled is higher than the number qualified, and the number of qualified leases is

higher than the number of productive leases. The bar heights in figure 53d represent the

total time elapsed since the leases were awarded.

There are two time lags represented in figures 53a-d. 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 time lag

depicted in figures 53a-d 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 about 1989. The apparent decreasing lag times

for leases issued after 1989 are caused by the fact that the lease evaluation process is not

yet complete.

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

(figure 53a). This is probably a reflection of two factors. First, the earliest deepwater

leases purchased were of very high interest to the lessees and, therefore, drilled quickly.

Second, increasing lease inventories during the late 1980’s meant that many leases could

not be evaluated right away (increased deepwater leasing in the mid to late 1980’s was

probably related to the introduction of area-wide leasing procedures, the drop in

minimum required bid from $150/acre to $25/acre, and the advent of 3-D seismic).

Figure 53b shows similar trends in the time lags between lease issue and lease
i

52

l

i

i

d 

il 

i

0

500

2500200015001000

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

YEAR LEASES ACQUIRED

NUMBER OF LEASES BID

$30$25$20$15$10$5$-

DOLLARS PER BARREL (modified from Energy Information 

Agency, Dept. of Energy)

Number of leasesbidOIL $/BBL 2yr avg. 

AUGER AND 

NEPTUNE LEASED (1985)

FIRST AUGER WELL (1987) 

FIRST AUGER PRODUCTION (1994)NEPTUNE FIRST WELL (1995)

Auger=GB426Neptune=AT575

DWRR

Oil price 2/15/00

69
70

0.0

2.0

4.0

6.0

8.0

10.0

12.0

1974-75 1976-77 1978-79 1980-81 1982-83 1984-85 1986-87 1988-89 1990-91 1992-93 1994-95 1996-97

Year Lease Acquired

Figure 53a. - Time lag from leasing to first well 

for producing deepwater fields.

YEARS TO 1ST WELL

Number of Years

0.0

2.0

4.0

6.0

8.0

10.0

12.0

1974-75 1976-77 1978-79 1980-81 1982-83 1984-85 1986-87 1988-89 1990-91 1992-93 1994-95 1996-97 Year Lease Acquired

Figure 53b. - Time lag from leasing to qualifying for 

producing deepwater fields. 

ADDITIONAL TIME TO QUALIFY

YEARS TO 1ST WELL

Number of Years

0.0

2.0

4.0

6.0

8.0

10.0

12.0

1974-75 1976-77 1978-79 1980-81 1982-83 1984-85 1986-87 1988-89 1990-91 1992-93 1994-95 1996-97

Year Lease Acquired

Figure 53c. - Time lag from leasing to first production for 

producing deepwater fields.

ADDITIONAL TIME TO 1st PRODUCTION

ADDITIONAL TIME TO QUALIFY

YEARS TO 1ST WELL

Number of Years
 

  

 



    

  

    

   



 







Figure 53d. - Time lag from leasing to first production, qualification and 

fi

t 

d

ti

f

ll d

t

ll

8.006.004.002.000.00

12.0010.00

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

Number of Years

YRS TO 1ST WELLYRS TO QLFY

 YRS TO 1ST PROD

29

1

10

16 92

134

40

72

39

27

33

48

11

Number of Leases Drilled

71
72

qualification. Exceptions include the long lag times between first drilling and qualifying

from 1974 to 1979. During the 1980’s there was also a gradual increase in the lag time

between drilling of the first well and qualifying the lease. During most of the 1980’s, it

took about 10 to 11 years for the average field to come on production. It is important to

note, however, that the time between drilling the first well and the beginning of

production dropped significantly throughout the 1980’s. That is, operators brought fields

online in about 10 years, despite the fact that the first wells weren’t drilled, on average,

until about the fourth year of the lease term by the late 1980’s.

Note that figure 53a indicates the first wells on leases that later produced were drilled

about 4 years into the lease term during the late 1980’s. However, figure 53d shows that

the first wells on all deepwater leases (including those that never produced) were drilled

about 6 years into the lease term during the late 1980’s. This trend is expected, since the

most promising prospects are usually drilled earlier in their lease terms.

In summary, the latest complete data indicate a 6-year average lag time between leasing

and initial drilling. On leases that later become productive, the average lag time between

leasing and initial drilling averages about 4 years. There is an additional 2-year average

lag before the well is qualified, and a total of 10 to 11 years from lease issuance until

production begins.

The combination of huge deepwater lease inventories and limited drilling capabilities

means that numerous leases remain untested when their terms expire. Figure 54 shows

historical lease activity trends. Once again, these data are complete only through about

1989, since most deepwater leases beyond that time are still under their primary term and

still under evaluation. Over 90 percent of leases acquired in 1974-1975 and 1978-1979

were drilled. About 70 percent of leases acquired in 1974-1975 later qualified (indicating

they discovered hydrocarbons) and about 50 percent came on production. Although less

than 15 percent of the leases issued in 1976-1977 were ever drilled, they all qualified and

came on production. The percentage of leases drilled decreased rapidly throughout the

1980’s as lease inventories swelled. As the percentage of leases drilled decreased, so did

the percentage of issued leases that qualified and the percentage that actually produced.

By the late 1980’s, less than 10 percent of issued deepwater leases were drilled, and less

than 5 percent produced. This situation is probably caused by drilling limitations and the

fact that only a finite number of leases can be evaluated within a given time frame.

Note that deepwater economics in the late 1980’s was significantly different than it is

today. Deepwater development technology was still in its infancy and the extraordinary

deepwater production rates were yet to be realized.

Although the percentage of leases drilled decreased during the late 1980’s, the actual

number of leases drilled generally increased along with the number of leases issued. This

eventually resulted in higher numbers of discoveries and producing leases from that crop

of leases. These relationships are shown in figures 55a and 55b. Figure 55a shows that

the number of leases issued through 1989 roughly correlated with the number of those

leases that were eventually drilled. Similarly, Figure 55b indicates that the number of
   

  

Figure 54. - Activity on deepwater leases.

0%

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

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

YEAR LEASE ACQUIRED

PERCENT OF LEASES WITH EACH ACTIVITY

25002000150010005000

NUMBER OF LEASES

% of leases drilled% of Leases that qualified

 % of Leases that are productive

Number of leases bid

73
Figure 55b. - Relationship between number of leases bid upon and resulting number of 

producing leases.

0

200

400

600

800

1,000

0 5 10 15 20 25 30 35

NUMBER OF PRODUCING LEASES

NUMBER OF

 LEASES BID

Figure 55c. - Relationship between number of leases drilled and resulting number of 

producing leases.

0

50

100

150

0 5 10 15 20 25 30 35

NUMBER OF PRODUCING LEASES

NUMBER OF 

LEASES DRILLED

Figure 55d. - Relationship between number of qualifying leases and resulting 

number of producing leases.

0

20

40

60

80

0 5 10 15 20 25 30 35

NUMBER OF PRODUCING LEASES

NUMBER OF 

QUALIFYING LEASES

Figure 55a. - Relationship between number of leases bid upon (1974-1989) and 

number of leases drilled. 

0

200

400

600

800

1,000

0 20 40 60 80 100 120 140 160

NUMBER OF LEASES DRILLED

NUMBER OF 

LEASES BID

74
75

leases issued through 1989 related to the number of those leases that eventually produced

hydrocarbons.

As expected, the number of deepwater leases drilled from 1974 through 1989 correlated

well with the number of those leases that later produced (figure 55c). Further, the

number of leases that qualified as capable of production related very well with the

number of those that eventually produced (figure 55d). In summary, historic data

indicate that increased leasing leads directly to increased drilling, qualifying, and

production (although not on a one-to-one basis).

Figure 56 shows the number of deepwater leases issued each year since 1992. This figure

also projects the exploratory evaluation of these leases assuming that (a) each lease is

drilled six years into its primary lease term (average from figure 53d), (b) 10 percent to

20 percent of these leases are eventually drilled (estimates from figure 54), and (c) future

lease acquisitions will not significantly impact drilling of the existing lease inventory.

Finally, we estimate the number of leases that can be evaluated by the anticipated GOM

rig fleet. The highest number of deepwater exploratory wells drilled in one year was

109 wells on 75 different leases in 1998. During this year there were an average

28 deepwater rigs drilling at any given time. We anticipate a slight (11% over 1998

numbers) increase in the number of deepwater rigs drilling in the deepwater GOM

through 2001. If we assume that new rigs will increase the number of exploratory wells

drilled by 11 percent over record 1998 levels, then 83 deepwater leases could be

evaluated each year.

On the basis of these assumptions, approximately 10 percent of the deepwater leases can

be evaluated. This is consistent with the percentage of deepwater leases drilled in the late

1980’s (the latest complete data). Since we assume all leases are drilled six years into

their primary terms (the average from figure 53d), the apex of rig constraints is between

2002 and 2004. Operators may evaluate more than 10 percent of their deepwater lease

inventory by spreading out their drilling programs wisely or bringing additional rigs into

the GOM. In summary, deepwater rig availability is a limiting factor, but the percentage

of leases that can be drilled with the expected GOM rig fleet is comparable to historic

averages.

Despite the difficulty evaluating deepwater leases, the future of deepwater GOM

exploration and production is very promising. Industry recently announced numerous

deepwater discoveries. Field sizes and flow rates of deepwater discoveries are often

outstanding. Although the traditional deepwater minibasin plays are far from mature, as

several recent discoveries attest, new deepwater plays near and even beyond the Sigsbee

Escarpment show that the deepwater GOM is still an emerging frontier. The Eastern

Gulf lease sale in 2001 will open up additional deepwater acreage for the first

competitive bidding in this area since 1988.

All phases of exploration and development moved steadily into deeper waters over the

past eight years. This trend is evident in seismic activity, leasing, bid rejects, exploratory

drilling, development drilling, discoveries, and production. Deepwater leasing was
0

200

400

600

800

1000

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

Year

Number of Leases

Deepwater Leases Issued

10% of Leases Drilled

20% of Leases Drilled

Figure 56. - Anticipated effect of rig constraints on lease evaluations.

Rig Capabilities

76
77

almost exclusively the realm of major oil and gas companies until 1996, when nonmajors

joined the trend. Major oil and gas companies continue to dominate deepwater

production, but production from nonmajors should increase in a few years when

anticipated discoveries on their 1996-1999 lease acquisitions begin producing.

The deepwater arena has come a long way in the past few years. The large volume of

active deepwater leases, the steady drilling program, and the growing deepwater

infrastructure all indicate that the deepwater GOM will continue to emerge as an integral

part of this Nation’s energy supply and remain one of the world’s premier oil and gas

basins.
78

Contributing Personnel 

This report includes contributions from the following individuals.

Kim Altobelli

Alex Alvarado

Debbie Armond

Adrian Cottrill

Thierry DeCort

Scott Edwards

Holly Gaudet

Fred Jacobs

Eric Kazanis

Charles Leyendecker

Tara Montgomery

Michelle Morin

Mike Nixdorff

Paul Post

Jim Regg

Chris Schoennagel

Jim Swaney

Fred Times

Janice Todesco

Mike Tolbert

Warren Williamson

Chee Yu

Vicki Zatarian
79

References 

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., B. J. Bascle, C. J. Kinler, M. T. Prendergast, and K. M. Ross, 2000,

Estimated Oil and Gas Reserves, Gulf of Mexico, December 31, 1997. Minerals

Management Service, Gulf of Mexico OCS Region. OCS Report MMS 2000-006. New

Orleans. 26 p.

Bollinger, D. B., 1999, “Demand for Marine Services Remains Volatile.” World Oil.

Vol. 220. No. 12. pp. 46-47.

DeLuca, M., 1999, “End of Mobile Drilling Unit Construction Cycle Nearing.” Offshore.

Vol. 59. No. 7. pp. 44-52.

Energy Information Agency, U.S. Department of Energy, “Domestic Crude Oil First

Purchase Prices.” Available: <<http://www.eia.doe.gov/pub/oil_gas/petroleum/data_

publications/petroleum_marketing_monthly/current/txt/tables21.txt>>. February 2000.

Gulf of Mexico Weekly Rig Locator, 1999 (December), “Working Rigs and Locations by

Rig Owner.” Vol. 13. No. 49.

Harding, B. W., 1999, “Worldwide Mobile Fleet Capabilities Shifting Toward

Deepwater.” Offshore. Vol. 59. No. 7. pp. 54-76.

Hart’s E&P Magazine, 1999 (December), “Gulf of Mexico Deep Production Sets

Records.” Vol. 72. No. 12. p. 17.

Kelly, P. L., 1999, “Big Challenges in the New Millennium.” World Oil. Vol. 220.

No. 12. pp. 39-40.

Melancon, J. M., and R. D. Baud, 2000, Gulf of Mexico Outer Continental Shelf Daily

Oil and Gas Production Rate Projections From 2000 Through 2004. Minerals

Management Service, Gulf of Mexico OCS Region. OCS Report MMS 2000-012. New

Orleans. 20 p.

Minerals Management Service, 1999, “Gulf of Mexico Deep Water Oil and Gas

Production Rises Dramatically.” News Release. October 18, 1999. Office of

Communications.

Rig Census, 1999 (December). Reed-Hycalog. Houston.
80

Appendix A – Announced Deepwater Discoveries and Fields

Field Year of First Year of Last

Nickname Block Operator Water Depth Discovery Date* Production Production

Aconcagua MC 305 Elf 7,039 ft

Allegheny GC 254 British-Borneo 3,186 ft Jan-85 1999

AmberJack MC 109 BP Exploration 1,058 ft Jul-84 1991

Angus GC 112 Shell Deepwater Dev. Inc. 1,465 ft Jun-97 1999

Ariel/Nakika MC 429 Shell Deepwater Dev. Inc. 6,274 ft Nov-95

Arnold EW 963 Marathon 1,752 ft Jun-96 1998

Atlantis GC 699 BP-Amoco 6,133 ft

Auger GB 426 Shell Deepwater Prod. Inc. 2,864 ft May-87 1994

Baha AC 600 Shell 7,620 ft May-96

Baldpate GB 260 Amerada Hess 1,605 ft Nov-91 1998

Bison GC 166 BP-Amoco 2,518 ft Mar-86

Black Widow AT 1 Mariner 1,850 ft May-86 2000

Boomvang EB 688 Kerr-McGee 3,665 ft May-88

Brutus GC 158 Shell Deepwater Prod. Inc. 2,877 ft Mar-89 2001

Bullwinkle GC 65 Shell Offshore Inc. 1,330 ft Oct-83 1989

Camden Hills MC 348 Marathon 7,200 ft

Cognac MC 194 Shell Offshore Inc. 1,023 ft Jul-75 1979

Cooper GB 387 EEX 2,163 ft Mar-89 1995 1999

Coulomb MC 657 Shell 7,500 ft Nov-87

Crazy Horse MC 778 BP-Amoco 6,044 ft

Crosby MC 899 BP-Amoco 4,165 ft Jan-98

Diamond MC 445 Oryx 2,095 ft Dec-92 1993 1999

Diana EB 945 Exxon 4,679 ft Aug-90

Dulcimer GB 367 Mariner 1,124 ft Feb-98 1999

East Anstey/Nakika MC 607 Shell Deepwater Dev. Inc. 6,590 ft Nov-97

El Toro GC 69 Shell Deepwater Dev. Inc. 1,428 ft Sep-84

Europa MC 935 Shell Deepwater Prod. Inc. 3,883 ft Apr-94 2000

Fourier/Nakika MC 522 Shell Deepwater Dev. Inc. 6,950 ft Jul-89

Fuji GC 506 Texaco 4,243 ft Jan-95

Gemini MC 292 Texaco 3,745 ft Sep-95 1999

Genesis GC 205 Chevron 2,599 ft Sep-88 1999

Glider GC 248 Shell 3,300 ft

Gomez MC 755 Union Pacific 3,010 ft Mar-86

Grand Canyon GC 141 Conoco 1,715 ft

Habanero GB 341 Shell 2,000 ft

Herschel/Nakika MC 520 Shell Deepwater Dev. Inc. 6,739 ft

Holstein GC 644 BP-Amoco 4,292 ft Feb-99

Hoover AC 25 Exxon 4,795 ft Jan-97

Horn Mountain MC 127 Vastar 5,443 ft

Jolliet GC 184 Conoco 1,722 ft Jul-81 1989

K2 GC 562 Conoco 3,979 ft

Kepler/Nakika MC 383 Shell Deepwater Dev. Inc. 5,759 ft Aug-87

King MC 084 Amoco Production 5,315 ft Jan-93

King MC 764 Shell Deepwater Dev. Inc. 3,265 ft 2000

King Kong GC 472 Shell Deepwater Dev. Inc. 3,817 ft Feb-89

King's Peak DC 133 Amoco Production 6,608 ft Mar-93

Knight GB 372 Santa Fe 1,740 ft

Lena MC 281 Exxon 1,017 ft May-76 1984

Leo MC 546 British Borneo 2,496 ft Feb-86

Macaroni GB 602 Shell Deepwater Dev. Inc. 3,600 ft 1999

Mad Dog GC 826 BP-Amoco 6,560 ft Nov-98

Madison AC 24 Exxon 4,851 ft Jun-98

Magnolia GB 783 Conoco 4,668 ft May-99

Marlin VK 915 Amoco Production 3,238 ft Jun-93 2000

Mars MC 807 Shell Deepwater Prod. Inc. 2,958 ft Apr-89 1996

Marshall EB 949 Exxon 4,376 ft Jul-98

Matterhorn MC 243 Elf 3,100 ft Sep-90

McKinley GC 416 Union 4,019 ft Aug-98

Medusa MC 582 Murphy 2,100 ft
81

Mensa MC 731 Shell Deepwater Prod. Inc. 5,330 ft Dec-86 1997

Metallica MC 911 BP-Amoco 7,000 ft

Mica MC 167 Exxon 4,356 ft

Mickey MC 211 Exxon 4,356 ft May-90

Mirage MC 941 Vastar 3,914 ft

Morpeth/Klamath EW 921 British-Borneo 1,706 ft Feb-91 1998

Nansen EB 602 Kerr-McGee 3,680 ft

Neptune AT 575 BP-Amoco 6,220 ft Sep-95

Neptune/Thor VK 825 Kerr-McGee 1,866 ft Nov-87 1997

Nile VK 914 BP-Amoco 3,534 ft Apr-97 2001

Nirvana MC 162 BP-Amoco 3,517 ft Nov-94

North Gemini MC 248 Chevron 3,290 ft 2001

Northwestern GB 200 Amerada Hess 1,471 ft May-98

Oregano GB 559 Shell 3,400 ft

Petronius VK 786 Texaco 1,754 ft Jul-95

Pluto/Blood Sweat & Tears MC 718 Mariner 2,786 ft Oct-95 2000

Pompano/Pompano II VK 990 BP Exploration 1,445 ft May-81 1994

Popeye GC 116 Shell Deepwater Prod. Inc. 2,067 ft Feb-85 1996

Poseidon GC 691 BP-Amoco 4,489 ft Feb-96

Ram Powell VK 956 Shell Deepwater Prod. Inc. 3,247 ft May-85 1997

Rocky GC 110 Shell Deepwater Prod. Inc. 1,621 ft Aug-87 1996

Salsa/Congor GB 171 Kerr-McGee 1,074 ft Apr-84 1998

Seattle Slew EW 914 Tatham 1,019 ft Aug-84 1993 1997

Serrano GB 516 Shell Deepwater Dev. Inc. 3,153 ft Jul-96

Sunday Silence EW 958 Sonat 1,464 ft Jul-94

Tahoe/Tahoe II VK 783 Shell Deepwater Prod. Inc. 1,492 ft Dec-84 1994

Troika GC 244 BP Exploration 2,681 ft May-94 1997

Typhoon GC 236 Chevron 2,005 ft May-98 2001

Ursa MC 810 Shell Deepwater Prod. Inc. 3,885 ft Oct-90 1999

Virgo VK 823 Elf 1,154 ft May-97 1999

Zinc MC 354 Exxon 1,478 ft Aug-77 1993

AT 008 Shell 3,135 ft Apr-97

EB 377 Shell 2,450 ft Oct-85

EB 992 Exxon 4,872 ft Nov-95

EW 1006 Walter Oil & Gas 1,832 ft Jan-88 1999

GB 208 Agip 1,270 ft Sep-91

GB 254 Chevron 1,920 ft Jul-93

GB 269 Texaco 1,036 ft Mar-96

GB 302 Conoco 2,411 ft Feb-91

GB 379 Conoco 2,076 ft Jul-85

GB 409 Texaco 1,357 ft May-97

GB 412 Union 1,313 ft Jul-84

GB 543 Conoco 2,000 ft

GC 021 Odeco 1,193 ft Oct-84

GC 027 Agip 1,593 ft Jul-89

GC 029 Placid 1,554 ft Jan-84 1988 1990

GC 037 British Borneo 2,024 ft

GC 039 Placid 1,917 ft Apr-84

GC 070 Conoco 1,874 ft Jun-84

GC 075 Oryx 2,172 ft May-85 1988 1989

GC 082 British Borneo 2,400 ft

GC 147 Texaco 1,275 ft May-88

GC 153 Marathon 1,500 ft

GC 153 Marathon 1,609 ft Apr-84

GC 162 Maxus (US) 2,578 ft Jul-89

GC 228 Texaco 1,638 ft Jul-85

GC 235 Placid 1,690 ft Oct-84

GC 463 BP-Amoco 4,032 ft Dec-98

MC 026 BP-Amoco 1,272 ft May-94

MC 113 Placid 1,857 ft Jan-76

MC 285 Texaco 3,068 ft Sep-87

MC 442 EEX 1,531 ft

MC 455 Union 1,400 ft Feb-86

MC 709 Arco 2,544 ft Feb-87

MC 929 Conoco 2,250 ft Nov-87
82

MC 942 Shell 3,930 ft

PI 525 BP-Amoco 3,430 ft Apr-96

VK 742 Texaco 1,004 ft Aug-97

VK 862 Walter Oil & Gas 1,043 ft Oct-76 1995

VK 864 Conoco 1,482 ft Oct-81

VK 873 Shell 3,810 ft Mar-88

* 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 MMS and they are not yet classified as fields by MMS.
83

Appendix B – Companies Defined as Majors in this Report

Group Name Company Name MMS Number

Arco ARCO Pipe Line Company 00486

Arco Atlantic Richfield Company 00002

Arco Atlantic Richfield Company 00967

Arco The Atlantic Refining Company 00002

Arco Vastar Offshore, Inc. 02316

Arco Vastar Pipeline, LLC 02317

Arco Vastar Resources, Inc. 01855

BP Amoco Amoco Canyon Company 00735

BP Amoco Amoco Corporation 02244

BP Amoco Amoco Foundation, Inc. 01679

BP Amoco Amoco Pipeline Company 00751

BP Amoco Amoco Production Company 00114

BP Amoco BP Alaska Exploration Inc. 00301

BP Amoco BP Amoco Corporation 02367

BP Amoco BP Exploration & Oil Inc. 01680

BP Amoco BP Exploration Inc. 00593

BP Amoco BP Exploration U.S.A., Inc. 00120

BP Amoco BP Oil Company 01680

BP Amoco BP Oil Corporation 00120

BP Amoco BP Prod. Corp. 02350

BP Amoco Sohio Alaska Petroleum Company 00113

BP Amoco Sohio Natural Resources 00113

BP Amoco Sohio Petroleum Company 00113

BP Amoco Sohio Petroleum Company 00593

Chevron Chevron Corporation 02335

Chevron Chevron Oil Company 00078

Chevron Chevron Oil Company of the Netherlands 01443

Chevron Chevron PBC, Inc. 01750

Chevron Chevron Pipe Line Company 00400

Chevron Chevron U.S.A. Inc. 00078

Chevron Gulf Oil Corporation 00112

Exxon Mobil Exxon Asset Holdings LLC 02356

Exxon Mobil Exxon Asset Management Company 02295

Exxon Mobil Exxon Corporation 00276

Exxon Mobil Exxon Pipeline Company 00103

Exxon Mobil Mobil Corporation 02221

Exxon Mobil Mobil E&P U.S. Development Corporation 02203

Exxon Mobil Mobil E&P U.S. Development Fund, L.P. 02209

Exxon Mobil Mobil Eugene Island Pipeline Company 00883

Exxon Mobil Mobil Exploration And Producing North

America Inc.

01055

Exxon Mobil Mobil Foundation, Inc. 01933

Exxon Mobil Mobil-GC Corporation 00565

Exxon Mobil Mobil NOC Inc. 00021

Exxon Mobil Mobil Oil Corporation 00039

Exxon Mobil Mobil Oil Exploration & Producing Southeast

Inc.

00540

Exxon Mobil Mobil Producing Texas & New Mexico Inc. 00565

Exxon Mobil Mobil-TransOcean Company 00637

Exxon Mobil Superior Oil Company 00047
84

Shell Shell Consolidated Energy Resources Inc. 01940

Shell Shell Deepwater Development Inc. 02139

Shell Shell Deepwater Production Inc. 02140

Shell Shell Energy Resources Inc. 00688

Shell Shell Frontier Oil & Gas Inc. 01728

Shell Shell Gas Gathering Company 02168

Shell Shell Gas Pipeline Company 01070

Shell Shell Land & Energy Company 01967

Shell Shell Offshore Inc. 00689

Shell Shell Offshore Properties and Capital II,

Inc.

02128

Shell Shell Oil Company 00117

Shell Shell Pipe Line Corporation 00124

Shell Shell Seahorse Company 02147

Shell Shell Western E&P Inc. 00832

Texaco Four Star Oil & Gas Company 00005

Texaco Four Star Oil & Gas Company 00005

Texaco Getty Oil Company 00005

Texaco Getty Pipeline, Inc. 01107

Texaco Getty Reserve Oil, Inc. 00578

Texaco Texaco Inc. 00040

Texaco Texaco Oils Inc. 00857

Texaco Texaco Pipeline Inc. 01107

Texaco Texaco Producing Inc. 00771

Texaco Texaco Seaboard Inc. 00025

Texaco Texaco Trading and Transportation, Inc. 02020
85

Appendix C – Subsea Completions

Area Block Well Name API Number Operator Completion

Date

Water Depth

BA 806 004 427024024500 Vastar Resources, Inc. 1997 164 ft

EB 112 003 608044015700 Agip Petroleum Co. Inc. 1996 638 ft

EB 117 001 608044016102 Vastar Offshore, Inc. 1997 570 ft

EB 157 002 608044015200 Agip Petroleum Co. Inc. 1996 941 ft

EB 168 001 608044016600 Walter Oil & Gas Corporation 1997 450 ft

EB A 124 001 427124010700 Walter Oil & Gas Corporation 1993 381 ft

EC 235 001 177034047300 Chevron U.S.A. Inc. 1986 121 ft

EC 328 005 177044080800 Louis Dreyfus Natural Gas Corp. 1997 243 ft

EC 341 001 177044067100 Walter Oil & Gas Corporation 1988 275 ft

EC 388 A002 608074015601 EEX Corporation 1997 2,096 ft

EI 175 004 177090084200 Vastar Resources, Inc. 1967 87 ft

EI 175 005 177090073300 Vastar Resources, Inc. 1966 90 ft

EI 175 006 177090073200 Vastar Resources, Inc. 1966 88 ft

EI 175 008 177090089700 Vastar Resources, Inc. 1975 83 ft

EI 175 009 177090090500 Vastar Resources, Inc. 1968 90 ft

EI 175 011 177090086800 Vastar Resources, Inc. 1973 83 ft

EI 175 012 177090087100 Vastar Resources, Inc. 1968 90 ft

EI 175 013 177090088000 Vastar Resources, Inc. 1969 87 ft

EI 179 001 177094088700 Kerr-McGee Corporation 1991 97 ft

EI 215 005 177094016400 PennzEnergy 1976 103 ft

EI 248 001 177094112300 Walter Oil & Gas Corporation 1997 155 ft

EI 294 005 177104126801 TDC Energy Corporation 1991 214 ft

EI 300 003 177104102700 Amoco Production Company 1983 212 ft

EI 301 004 177104134000 Amoco Production Company 1991 232 ft

EI 301 005 177104136700 Amoco Production Company 1994 231 ft

EI 320 003 177104128700 Forest Oil Corporation 1994 244 ft

EI 322 005 177104134100 Amoco Production Company 1996 242 ft

EI 331 004 177104046800 Shell Offshore Inc. 1975 242 ft

EI 331 005 177104047700 Shell Offshore Inc. 1976 242 ft

EI 349 012 177104100500 Marathon Oil Company 1990 337 ft

EI 364 003 177104138000 The Louisiana Land and Exploration Company 1996 357 ft

EW 914 002 608105002200 Tatham Offshore, Inc. 1993 946 ft

EW 917 001 608105006500 Marathon Oil Company 1998 1,195 ft

EW 963 001 608105006000 Marathon Oil Company 1998 1,740 ft

EW 963 002 608105006800 Marathon Oil Company 1998 1,758 ft

EW 965 001 608105006200 British-Borneo Exploration, Inc. 1998 1,694 ft

EW 989 001 608104008600 Kerr-McGee Corporation 1994 565 ft

EW 989 002 608104008701 Kerr-McGee Corporation 1995 565 ft

EW 999 001 608104003202 Placid Oil Company 1989 1,462 ft

EW 1006 002 608105004100 Walter Oil & Gas Corporation 1997 1,884 ft

GB 70 001 608074007000 Newfield Exploration Company 1995 755 ft

GB 70 001 608074007001 Newfield Exploration Company 1997 750 ft
86

GB 71 002 608074013000 Newfield Exploration Company 1995 750 ft

GB 108 001 608074020600 Kerr-McGee Oil & Gas Corporation 1999 619 ft

GB 117 001 608074013500 Flextrend Development Company 1996 922 ft

GB 117 002 608074014901 Flextrend Development Company 1997 924 ft

GB 134 001 608074062900 ATP 1997 520 ft

GB 152 001 608074020800 Kerr-McGee Oil & Gas Corporation 1999 619 ft

GB 161 001 608074015801 PennzEnergy Exploration and Production, L.L.C. 1999 972 ft

GB 172 B001 608074018200 Shell Offshore Inc. 1998 693 ft

GB 172 B002 608074018401 Shell Offshore Inc. 1999 693 ft

GB 172 B003 608074019700 Shell Offshore Inc. 1999 663 ft

GB 179 001 608074063700 Walter Oil & Gas Corporation 1997 712 ft

GB 216 002 608074081901 Amerada Hess Corporation 1999 1,456 ft

GB 224 005 608074061800 Kerr-McGee Oil & Gas Corporation 1991 742 ft

GB 235 003 608074010600 The Louisiana Land and Exploration Company 1996 785 ft

GB 240 003 608074013100 Mariner Energy, Inc. 1996 832 ft

GB 367 002 608074064100 Mariner Energy, Inc. 1999 1,122 ft

GB 378 002 608074015700 Sonat Exploration GOM Inc. 1997 495 ft

GB 387 SB001 608074014001 EEX Corporation 1996 2,081 ft

GB 388 SA001 608074005400 EEX Corporation 1995 2,097 ft

GB 388 SA002 608074008401 EEX Corporation 1997 2,097 ft

GB 602 A002 608074014401 Shell Deepwater Development Inc. 1999 3,708 ft

GB 602 A005 608074019401 Shell Deepwater Development Inc. 1999 3,693 ft

GC 20 001 608114021300 Reading & Bates Development Co. 1999 880 ft

GC 29 A003 608114009100 Placid Oil Company 1989 1,526 ft

GC 31 004 608114004701 EP Operating Limited Partnership 1988 2,243 ft

GC 31 006 608114009600 EP Operating Limited Partnership 1989 2,234 ft

GC 60 001 608114019800 Mobil Oil Exploration & Producing Southeast Inc. 1996 870 ft

GC 60 002 608114020101 Mobil Oil Exploration & Producing Southeast Inc. 1996 868 ft

GC 72 A001 608115008500 Shell Deepwater Production Inc. 1996 2,040 ft

GC 110 001 608114020600 Shell Offshore Inc. 1996 1,730 ft

GC 113 A002 608115012701 Shell Deepwater Development Inc. 1999 2,045 ft

GC 116 A002 608115008600 Shell Deepwater Production Inc. 1996 2,046 ft

GC 116 A003 608115012200 Shell Deepwater Production Inc. 1998 2,046 ft

GC 136 006 608114020000 Texaco 1995 860 ft

GC 136 007 608114020401 Texaco 1995 1,040 ft

GC 200 TA001 608114021600 BP Exploration & Oil Inc. 1997 2,670 ft

GC 200 TA003 608114021800 BP Exploration & Oil Inc. 1997 2,670 ft

GC 200 TA004 608114021901 BP Exploration & Oil Inc. 1999 2,670 ft

GC 200 TA005 608114020501 BP Exploration & Oil Inc. 1998 2,670 ft

GC 254 004 608115008301 British-Borneo Exploration, Inc. 1999 3,225 ft

GC 254 005 608115009000 British-Borneo Exploration, Inc. 1999 3,234 ft

GI 41 004 177174009600 Vastar Resources, Inc. 1985 100 ft

GI 41 005 177174009500 Vastar Resources, Inc. 1978 91 ft

GI 41 006 177174009700 Vastar Resources, Inc. 1978 91 ft

GI 43 004 177174009800 Vastar Resources, Inc. 1978 114 ft

GI 47 004 177174009300 Vastar Resources, Inc. 1978 88 ft
87

GI 47 006 177174018500 Vastar Resources, Inc. 1986 97 ft

HI A 7 004 427044011600 Texaco 1984 120 ft

HI A 309 007 427114070100 Coastal Oil & Gas Corporation 1995 213 ft

HI A 320 001 427114077400 Walter 1997 237 ft

HI A 325 008 427114064000 Pennzoil Exploration and Production Company 1989 231 ft

HI A 325 009 427114064100 Pennzoil Exploration and Production Company 1989 231 ft

HI A 370 003 427114065100 Kerr-McGee Oil & Gas Corporation 1993 375 ft

HI A 373 001 427114065000 EOG Resources, Inc. 1992 375 ft

HI A 378 001 427114080601 Kerr-McGee 1999 332 ft

HI A 378 B018 427114075700 Kerr-McGee 1996 360 ft

HI A 519 004 427094093200 Coastal Oil & Gas Corporation 1991 220 ft

HI A 573 006 427094053700 Union Oil Company of California 1980 350 ft

HI A 587 002 427094089602 Panaco, Inc. 1990 467 ft

MC 28 TB002 608174051600 BP Exploration & Oil Inc. 1996 1,853 ft

MC 28 TB005 608174051900 BP Exploration & Oil Inc. 1996 1,853 ft

MC 28 TB006 608174052000 BP Exploration & Oil Inc. 1998 1,853 ft

MC 72 TB001 608174051500 BP Exploration & Oil Inc. 1996 1,853 ft

MC 292 001 608174050900 Texaco 1999 3,405 ft

MC 292 003 608174083201 Texaco 1999 3,393 ft

MC 292 004 608174083301 Texaco 1999 3,393 ft

MC 354 A003 608174044700 Exxon Corporation 1993 1,460 ft

MC 355 A001 608174044900 Exxon Corporation 1993 1,460 ft

MC 355 A002 608174044800 Exxon Corporation 1993 1,458 ft

MC 355 A004 608174084301 Exxon Corporation 1999 1,458 ft

MC 357 002 608174053801 Newfield Exploration Company 1998 445 ft

MC 401 001 608174032901 Kerr-McGee Oil & Gas Corporation 1993 1,367 ft

MC 401 002 608174034600 Kerr-McGee Oil & Gas Corporation 1993 1,700 ft

MC 441 A004 608174037601 EEX Corporation 1993 1,438 ft

MC 441 A009 608174041500 EEX Corporation 1993 1,438 ft

MC 441 B006 608174038400 EEX Corporation 1992 1,531 ft

MC 441 B007 608174040002 EEX Corporation 1993 1,531 ft

MC 441 B008 608174040100 EEX Corporation 1992 1,531 ft

MC 445 001 608174042900 Kerr-McGee Oil & Gas Corporation 1993 2,094 ft

MC 445 002 608174047300 Kerr-McGee Oil & Gas Corporation 1994 2,095 ft

MC 485 A001 608174041600 EEX Corporation 1993 1,438 ft

MC 686 A001 608174054100 Shell Deepwater Production Inc. 1997 5,292 ft

MC 687 A002 608174054000 Shell Deepwater Production Inc. 1998 5,292 ft

MC 730 A003 608174054200 Shell Deepwater Production Inc. 1997 5,295 ft

MC 783 004 608164013401 Shell Deepwater Production Inc. 1993 1,494 ft

MC 807 004 608174038800 Shell Deepwater Production Inc. 1996 2,956 ft

MC 825 005 608164034400 Kerr-McGee Oil & Gas Corporation 1999 1,711 ft

MP 145 005 177254047300 OXY USA Inc. 1989 213 ft

MP 149 002 177254058901 Walter Oil & Gas Corporation 1994 220 ft

MP 260 001 177244081400 Santa Fe Snyder Corporation 1999 315 ft

MP 262 001 177244076100 CXY Energy Offshore Inc. 1996 283 ft

MP 281 001 177244069100 Walter Oil & Gas Corporation 1994 293 ft
88

MP 291 001 177244056600 Allied Natural Gas Corporation 1995 272 ft

MU 131 001 177254060100 ATP Oil & Gas Corporation 1998 165 ft

MU A 327 004 427114071200 Hall-Houston Oil Company 1994 220 ft

PN 1010 001 427014005000 Walter 1999 128 ft

SM 61 005 177074029400 Chevron U.S.A. Inc. 1984 130 ft

SM 67 001 177074039000 Cockrell Oil Corporation 1984 130 ft

SS 176 007 177114099800 Chevron U.S.A. Inc. 1990 100 ft

SS 204 001 177110067000 Union Pacific Resources Company 1995 103 ft

SS 204 002 177110067200 Union Pacific Resources Company 1983 100 ft

SS 204 004 177110081400 Union Pacific Resources Company 1969 103 ft

SS 217 002 177110055500 Kerr-McGee Corporation 1971 114 ft

SS 269 005 177124010700 Union Oil Company of California 1976 187 ft

SS 274 001 177122001100 Apache Corporation 1969 219 ft

SS 274 005 177124008600 Apache Corporation 1975 210 ft

SS 276 002 177124058800 Forest Oil Corporation 1998 215 ft

SS 316 002 177124043400 Hall-Houston Oil Company 1991 295 ft

SS 317 001 177124038600 Newfield Exploration Company 1990 295 ft

SS 321 001 177124057000 ATP Oil & Gas Corporation 1997 323 ft

SS 326 001 177124058700 Walter Oil & Gas Corporation 1998 364 ft

SS 361 001 177124054900 Phillips Petroleum Company 1998 405 ft

ST 169 005 177154032600 Samedan Oil Corporation 1980 88 ft

ST 169 006 177154062300 Samedan Oil Corporation 1985 102 ft

ST 177 001 177154007800 Chevron U.S.A. Inc. 1976 144 ft

ST 231 001 177164019900 SOCO Offshore, Inc. 1998 238 ft

VK 28 A008 608164018600 BP Exploration & Oil Inc. 1995 1,290 ft

VK 113 A003 608115013100 Shell Deepwater Development Inc. 1999 1,968 ft

VK 783 005 608164021701 Shell Deepwater Production Inc. 1996 1,142 ft

VK 784 001 608164023200 Shell Deepwater Production Inc. 1996 1,750 ft

VK 825 004 608164033201 Kerr-McGee Oil & Gas Corporation 1998 1,722 ft

VK 862 002 608164021600 Walter Oil & Gas Corporation 1995 1,067 ft

VK 944 001 608164032200 Elf Exploration, Inc. 1997 740 ft

VK 986 001 608164022800 Walter Oil & Gas Corporation 1995 893 ft

VR 215 006 177054028500 Newfield Exploration Company 1979 140 ft

VR 246 009 177054034600 Chevron U.S.A. Inc. 1982 155 ft

VR 302 002 177064021701 CXY Energy Offshore Inc. 1977 197 ft

VR 320 009 177064064200 Oryx Energy Company 1991 206 ft

WC 192 001 177004055500 Diamond Shamrock 1982 54 ft

WC 459 003 177024062900 Conoco Inc. 1985 135 ft

WC 548 001 177024106000 Walter Oil & Gas Corporation 1994 185 ft

WC 584 001 177024085700 Walter Oil & Gas Corporation 1989 237 ft

WC 592 001 177024106301 Walter Oil & Gas Corporation 1995 252 ft

WC 638 001 177024116900 Kerr-McGee Oil & Gas Corporation 1998 373 ft

WD 45 001 177190038200 CXY Energy Offshore Inc. 1959 50 ft

WD 45 002 177190038300 CXY Energy Offshore Inc. 1959 72 ft

WD 45 007 177190038402 CXY Energy Offshore Inc. 1981 50 ft

WD 62 005 177194027900 Mesa Operating 1985 130 ft
89

WD 70 001 177190062800 Vastar Resources, Inc. 1958 143 ft

WD 70 003 177190063000 Vastar Resources, Inc. 1961 143 ft

WD 71 001 177190061900 Vastar Resources, Inc. 1961 142 ft

WD 77 001 177194065504 ATP Oil & Gas Corporation 1999 187 ft

WD 106 002 177194056800 Walter Oil & Gas Corporation 1995 234 ft

WD 107 001 177194056400 Walter Oil & Gas Corporation 1996 222 ft