OCS-Related Infrastructure in the 

Gulf of Mexico Fact Book
OCS-Related Infrastructure in the 

Gulf of Mexico Fact Book

Preparer 

The Louis Berger Group, Inc. 

Prepared under MMS Contract 

1435-01-99-CT-30955 

by 

The Louis Berger Group, Inc. 

100 Halsted Street 

East Orange, New Jersey 

Published by 

U.S. Department of the Interior 

Minerals Management Service New Orleans

Gulf of Mexico OCS Region June 2004
iii 

DISCLAIMER 

This report was prepared under contract between the Minerals Management 

Service (MMS) and The Louis Berger Group, Inc. This report has been 

technically reviewed by the MMS, and it has been approved for publication. 

Approval does not signify that the contents necessarily reflect the views and 

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

constitute endorsement or recommendation for use. It is, however, exempt from 

review and compliance with the MMS editorial standards. 

REPORT AVAILABILITY 

Extra copies of this report may be obtained from the Public Information Office 

(Mail Stop 5034) at the following address: 

U.S. Department of the Interior 

Minerals Management Service 

Gulf of Mexico OCS Region 

Public Information Office (MS 5034) 

1201 Elmwood Park Boulevard 

New Orleans, Louisiana 70123-2394 

Telephone: (504)736-2519 or 

 1-800-200-GULF 

CITATION 

Suggested citation: 

The Louis Berger Group, Inc. 2004. OCS-Related Infrastructure in the Gulf of Mexico Fact 

Book. U.S. Dept. of the Interior, Minerals Management Service, Gulf of Mexico OCS 

Region, New Orleans, LA. OCS Study MMS 2004-027. 249 pp. 

ABOUT THE COVER 

The cover contains the following photographs clockwise from the upper left: Port of Houston 

(source - www.portofhouston.com); oil platform (source - www.portfourchonla.com); Port 

Fourchon (source - www.portfourchonla.com); and, Port Morgan City (source - 

www.portofmc.com). 
v

TABLE OF CONTENTS

Page

List of Figures ................................................................................................................................ vii

List of Tables...................................................................................................................................ix

List of Acronyms..............................................................................................................................xi

1.0 Introduction ..........................................................................................................................1

2.0 Platform Fabrication Yards ..................................................................................................9

2.1 Introduction ..............................................................................................................9

2.2 Description and Typical Facilities ..........................................................................10

2.3 Industry Characteristics .........................................................................................13

2.4 Regulations ............................................................................................................15

2.5 Industry Trends and Outlook .................................................................................16

3.0 Port Facilities......................................................................................................................21

3.1 Introduction ............................................................................................................21

3.2 Description and Typical Facilities ..........................................................................23

3.3 Industry Characteristics .........................................................................................29

3.4 Regulations ............................................................................................................35

3.5 Industry Trends and Outlook .................................................................................37

3.6 Summary................................................................................................................41

4.0 Shipyards/Shipbuilding ......................................................................................................43

4.1 Introduction ............................................................................................................43

4.2 Description and Typical Facilities ..........................................................................43

4.3 Industry Characteristics .........................................................................................45

4.4 Regulations ............................................................................................................48

4.5 Industry Trends and Outlook .................................................................................51

4.6 Inventory of Major Gulf Coast Facilities.................................................................56

5.0 Support and Transport Facilities........................................................................................65

5.1 Introduction ............................................................................................................65

5.2 Description and Typical Facilities ..........................................................................65

5.3 Industry Characteristics .........................................................................................67

5.4 Regulations ............................................................................................................70

5.5 Industry Trends and Outlook .................................................................................72

6.0 Waste Management Facilities............................................................................................77

6.1 Introduction ............................................................................................................77

6.2 Description and Typical Facilities ..........................................................................78

6.3 Industry Characteristics .........................................................................................79

6.4 Regulations ............................................................................................................92

6.5 Industry Trends and Outlook .................................................................................94

7.0 Pipelines.............................................................................................................................97

7.1 Introduction ............................................................................................................97
vi

TABLE OF CONTENTS

(continued)

Page

7.2 Description and Typical Facilities ..........................................................................98

7.3 Industry Characteristics .......................................................................................101

7.4 Regulations ..........................................................................................................108

7.5 Industry Trends and Outlook ...............................................................................112

8.0 Pipe Coating Facilities .....................................................................................................123

8.1 Introduction ..........................................................................................................123

8.2 Description and Typical Facilities ........................................................................123

8.3 Industry Characteristics .......................................................................................128

8.4 Regulations ..........................................................................................................129

8.5 Industry Trends and Outlook ...............................................................................131

9.0 Natural Gas Processing Plants........................................................................................133

9.1 Introduction ..........................................................................................................133

9.2 Description and Typical Facilities ........................................................................134

9.3 Industry Characteristics .......................................................................................137

9.4 Regulations ..........................................................................................................140

9.5 Industry Trends and Outlook ...............................................................................140

10.0 Natural Gas Storage Facilities.........................................................................................145

10.1 Introduction ..........................................................................................................145

10.2 Description and Typical Facilities ........................................................................146

10.3 Industry Characteristics .......................................................................................148

10.4 Regulations ..........................................................................................................152

10.5 Industry Trends and Outlook ...............................................................................152

11.0 Refineries .........................................................................................................................157

11.1 Introduction ..........................................................................................................157

11.2 Description and Typical Facilities ........................................................................159

11.3 Industry Characteristics .......................................................................................162

11.4 Regulations ..........................................................................................................165

11.5 Industry Trends and Outlook ...............................................................................167

12.0 Petrochemical Plants.......................................................................................................171

12.1 Introduction ..........................................................................................................171

12.2 Description and Typical Facilities ........................................................................173

12.3 Industry Characteristics .......................................................................................176

12.4 Regulations ..........................................................................................................178

12.5 Industry Trends and Outlook ...............................................................................180

13.0 Bibliography .....................................................................................................................185

Appendix I. Infrastructure Database Description and Queries...............................................197

Appendix II. Additional Port Facility Information .....................................................................203

Appendix III. Description of OCSGEN .....................................................................................229
vii

LIST OF FIGURES

 

 No. Page 

 1.1 Active Leases in the Gulf of Mexico by Water Depth..............................................2

 1.2 Annual Percent Total Active Leases by Water Depth.............................................3

 1.3 Onshore Support Infrastructure...............................................................................5

 1.4 Onshore Infrastructure Supported by OCS Activities..............................................6

 2.1 Permanent Production Systems on the Gulf of Mexico OCS...............................11

 3.1 Principal Commodity Groups Carried by Water (2001).........................................22

 3.2 Distribution of OSV Bases in the Gulf (2000)........................................................25

 4.1 Number of Production Workers by Shipyard Type................................................45

 4.2 Gulf of Mexico Supply Boat Total Fleet Size.........................................................47

 4.3 Supply Boat Market Share by Vessels in the Gulf of Mexico................................48

 4.4 Commercial Shipbuilding Orderbook History........................................................52

 4.5 U.S. Shipbuilding and Repair Industry Capital Investments .................................53

 4.6 Percentage of Total Gulf of Mexico Fleets for Large Companies

(more than 10 vessels)..........................................................................................55

 5.1 Western Gulf Planning Area ..................................................................................68

 5.2 Central Gulf Planning Area....................................................................................69

 6.1 Injection Wells for Oilfield Waste...........................................................................83

 6.2 Salt Cavern Waste Disposal..................................................................................86

 6.3 Municipal Landfill Oilfield Waste Disposal.............................................................89

 7.1 Natural Gas Pipes..................................................................................................97

 7.2 Estimated Region-to-Region Natural Gas Pipeline Capacity at End 

of 2000 (MMcf/d)..................................................................................................103

 7.3 Production of Crude Oil by PAD District and State (million barrels)...................105

 7.4 Annual Additions to Natural Gas Pipeline Capacity by Region...........................113

 7.5 Annual Natural Gas Pipeline Construction Expenditures by Region..................113

 7.6 Percent of Total Energy Fueled by Natural Gas in the U.S. ..............................114

 7.7 Gulfstream Natural Gas Project...........................................................................115

 7.8 Corporate Realignments......................................................................................118

 7.9 Total Crude Petroleum and Petroleum Products Carried by Pipelines

as a Percent of Total Petroleum Transported .....................................................121

 8.1 External/Internal Fusion Bonded Epoxy Coating Plant.......................................129

 9.1 Variety of Natural Gas Processing Procedures...................................................135

 9.2 Natural Gas Processing Products .......................................................................135

 9.3 U.S. Natural Gas Processing Plants................................................................... 139

 9.4 Natural Gas Processed by Top Ten States (2000) ............................................139

 9.5 Total Liquids Extracted by Top Ten States (2000) .............................................140

 10.1 Pressure and Volume Relationship for a Storage Reservoir ..............................146

 10.2 U.S. Natural Gas Storage Distribution.................................................................149

 10.3 Locations of Existing Natural Gas Underground Storage Fields in the U.S. .....150

 10.4 Working Gas in Storage by Region .....................................................................153

 11.1 Petroleum Products and Uses (1999 Percent Refinery Yield)............................158

 11.2 The Refining Process...........................................................................................160

 11.3 U.S. Refineries and Capacity by State as of January 1, 2001............................162

 11.4 Imports of Crude Oil and Petroleum Products by PAD District (2000)...............164

 11.5 Movements of Petroleum Products between U.S. Regions (2000) ....................164
viii

LIST OF FIGURES

(continued)

 

 No. Page 

 11.6 Number and Capacity of Operable Petroleum Refineries...................................169

 12.1 Organic Chemicals and Building Blocks Flow Diagram......................................171

 12.2 Chemical Industry Energy Use by Fuel – 1994 (trillion Btu) ...............................174

 12.3 Sector Energy Use – 1994 (trillion Btu)...............................................................175

 12.4 Value of Shipments for Top Ten States (1996)...................................................177

 12.5 Type of Construction Projects – 1996 to 2000 Average .....................................180

 12.6 U.S. Ethylene Economics....................................................................................181

 12.7 Top Shareholders of North American Capacity...................................................182
ix

LIST OF TABLES

 No. Page

 2.1 Platform Fabrication Facilities in the Gulf..............................................................19

 2.2 Water Depth Records ............................................................................................20

 3.1 U.S. Ports Handling More Than 10 Million Tons in 1997......................................23

 3.2 Principal Offshore Support Vehicle Bases for the Oil and Gas Industry 

in the Gulf of Mexico (2000)...................................................................................26

 3.3 Major U.S. Shipbuilding and Repair Bases (October 1998) .................................27

 3.4 Vessel Maintenance Operations, Typical Raw Material Inputs, and 

Pollution Outputs....................................................................................................32

 3.5 GOM Lease Sale Schedule – Proposed for 2002-2007........................................38

 3.6 Major Port Facilities Servicing the Offshore Oil and Gas Industry in the Gulf......39

 4.1 Number of Shipyards by Type and Region ...........................................................46

 4.2 Primary Shipyards in the Gulf Region which Support the Offshore Oil 

and Gas Industry....................................................................................................57

6.1 Waste Management Facilities in the Gulf which Support the Offshore Oil 

and Gas Industry....................................................................................................80

 6.2 Disposal Costs for Various Industrial Wastes .......................................................92

 6.3 Summary of Federal Rules Governing OCS Discharges and Injections ..............93

 7.1 Major Additions to U.S. Interstate Natural Gas Pipeline Capacity

1991-2000 ..............................................................................................................99

 7.2 Movements of Crude Oil and Petroleum Products by Pipeline Between 

PAD Districts, 2002 (thousand barrels)...............................................................106

 7.3 Summary of Federal Offshore Pipeline Miles by Area and Diameter

in the Gulf.............................................................................................................108

 7.4 Shifts in Ownership of Selected Major Interstate Natural Gas 

Pipeline Companies since 1990 ..........................................................................119

 8.1 Comparison of Pipeline Coating Systems Currently Used .................................127

 9.1 Components Found in Natural Gas .....................................................................133

 9.2 Natural Gas Processing Plants in the United States (as of January 1, 2001)....138

 9.3 U.S. Processing Facilities under Construction....................................................143

 10.1 Characteristics of Natural Gas Storage Facilities................................................147

 10.2 Summary of Underground Storage, by Region and Type (2000) .......................149

 11.1 Top Ten Petroleum Refining States as of January 1, 2002 ................................163

 11.2 Refineries in the Gulf Region...............................................................................170

 12.1 Industry Specific Technologies............................................................................172

 12.2 Organic Chemical Facility Characteristics...........................................................174

 12.3 Value of Shipments within Chemical Industry (billion dollars, 1996) ..................178

 12.4 Petrochemical Construction/Expansion Projects in the United States ...............183
xi

LIST OF ACRONYMS

AAPA – American Association of Port Authorities

AHT – Anchor Handling Tug

AHTS – Anchor Handling Tug/Supply Vessel

ANS – Alaskan North Slope

ATSDR – Agency for Toxic Substances and Disease Registry

bbl – Barrel

bcfd – Billion Cubic Feet per Day

BOE – Barrels of Oil Equivalent

CAA – Clean Air Act

CAAA – Clean Air Act Amendments

CDS – Construction Differential Subsidies

CERCLA – Comprehensive Environmental Response, Compensation, and Liability Act

CFC – Chlorofluorocarbon 

CO – Carbon Monoxide

CWA – Clean Water Act

DOE – United States Department of Energy

dth – Decatherm ( equivalent to 1 MMBtu)

DP – Dynamic Positioning

DSV – Diving Support Vessel

DWRRA – Deepwater Royalty Relief Act

DWT – Dry Weight Ton

E & P – Exploration and Production

EIA – Environmental Information Administration

EIS – Environmental Impact Statement

EPA – United States Environmental Protection Agency

EPCRA – Emergency Planning and Community Right-to-Know Act

FAA – Federal Aviation Administration

FERC – Federal Energy Regulatory Commission

FPSO – Floating Production, Storage, and Offloading

FSU – Floating Storage Unit

GDP – Gross Domestic Product

GIS – Geographic Information System

GOM – Gulf of Mexico

HAP – Hazardous Air Pollutant

HON – Hazardous Organic National Emissions Standards for Hazardous Air Pollutants

JU – Jack-Up Drilling Units

LDC – Local Distribution Company

LEPC – Local Emergency Planning Commission
xii

LIST OF ACRONYMS

(continued)

LMOGA – Louisiana Mid-Continent Oil and Gas Association

LNG – Liquified Natural Gas

LPG – Liquified Petroleum Gas

MACT – Maximum Achievable Control Technology

MARAD – Maritime Administration

Mcfd – Million Cubic Feet per Day

MoDU – Mobile Drilling Units

MMS – Minerals Management Service

MRO – Material Requisition Order

MSB – Major Shipbuilding Base

MSC – Military Sealift Command

MSDS – Material Safety Data Sheet

MSV – Multi-function Service Vessel

MSW – Municipal Solid Waste

NDRF – National Defense Reserve Fleet

NESHAP – National Emission Standards for Hazardous Air Pollutants

NGL – Natural Gas Liquids

NHS – National Highway System

NOAA – National Oceanographic and Atmospheric Administration

NORM – Naturally Occurring Radioactive Materials

NOW – Nonhazardous Oilfield Waste

NPDES – National Pollution Discharge Elimination System

NSPS – New Source Performance Standards

NTSB – National Transportation Safety Board

OCS – Outer Continental Shelf

OEM – Original Equipment Manufacturer

OPA – Oil Pollution Act of 1990

OPEC – Organization of the Petroleum Exporting Countries

OSHA – Occupational Safety and Health Administration

OSV – Offshore Support Vehicle

PAD – Petroleum Administration for Defense

PCB – Polychlorinated Biphenyl

PIG – Pipeline Inspection Gauge

PM10 – Particulate Matter less than 10 microns in diameter

PMN – Pre-Manufacture Notice

PRP – Potentially Responsible Parties

PSV – Platform Supply Vessel

PTSA – Port and Tanker Safety Act of 1978

PWSA – Ports and Waterways Safety Act

RCRA – Resource Conservation and Recovery Act

RVP – Reid Vapor Pressure
xiii

LIST OF ACRONYMS

(continued)

SARA – Superfund Amendments and Reauthorization Act of 1986

SCADA – Supervising Control and Data Acquisition

SDWA – Safe Drinking Water Act

SERC – State Emergency Response Commission

SIC – Standard Industry Code

TAC – Texas Administrative Code

TAP – Toxic Air Pollutants

tcf – Trillion Cubic Feet

TEA-21 – Transportation Equity Act for the 21st Century

TEU – Twenty-Foot Equivalent units

TLP – Tension Leg Platform

TOC – Total Organic Compounds

TPH – Total Petroleum Hydrocarbons

TRI – Toxic Release Inventory

TSCA – Toxic Substances Control Act

TSDF – Treatment, Storage, and Disposal Facilities

USACE – United States Army Corps of Engineers

USDW – Underground Source of Drinking Water

VOC – Volatile Organic Carbon

VTSS – Vessel Traffic Service/Separation Schemes
1

1.0 INTRODUCTION

The history of the offshore oil and gas business is commonly dated to 1947 when Kerr McGee, 

an Oklahoma independent oil and gas company, drilled the first well out of the sight of land in 

the Gulf of Mexico (“GOM” or “Gulf”). Since that time, the offshore GOM has been a vibrant 

area of oil and gas exploration, development, and production. One significant challenge in the 

early days of offshore oil and gas development was getting men, equipment, and supplies to 

these remote production facilities. One could argue that half the innovation with offshore

production was associated with just supplying these facilities.

Over the years, a network of support facilities, ports, roads, pipelines, and processing facilities 

have arisen to support offshore production. Since this infrastructure has been developed to 

support offshore activities, when the offshore industry experiences a downturn, so too do the 

supporting infrastructure businesses. 

The period from 1950 to the 1970s was the high point of interest for the GOM. During that 

period, the GOM became one of the most explored and developed offshore basins in the world. 

By the late 1980s, however, the Gulf had become an area of decreasing interest for world-wide 

oil and gas development. The region was considered a relatively mature basin, with limited 

potential for growth relative to other emerging frontier areas around the globe. At the time, the 

Gulf was disparagingly referred to as the “Dead Sea.”

However, in the mid 1990s, activity in the Gulf experienced a dramatic shift spurred in large part 

by the passage of the Deepwater Royalty Relief Act (“DWRRA” or “Act”). While deepwater 

development has its origins as early as 1978 with Shell’s Cognac Field, deepwater drilling was 

technologically challenging as well as financially risky. Locating prospective oil and gas fields in 

deep water was difficult, while producing and extracting oil from deepwater areas was, for the 

most part, cost ineffective. In recent years, 3-D seismic technology has provided a more 

detailed look at potential reserves while advances have been made in exploration techniques 

and platform design and construction and subsea completions.

Even more of a limitation than technological obstacles was an economic impediment in the form 

of royalty payments. These payments were due immediately upon extracting oil and gas from 

federally leased offshore sites, creating a financial barrier in reaching the vast amounts of

untapped resources in the Gulf. It was not until the passage of the DWRRA in 1995 that the 

appropriate incentives were sent to the industry to begin to explore this new frontier in the GOM. 

The DWRRA granted royalty relief.

The DWRRA, passed in 1995, allows the Secretary of the Interior to grant royalty suspension 

volumes for fields in the Gulf of Mexico that were: (1) under lease prior to the enactment of 

DWRRA; (2) have never produced other than test production; (3) would not be economic 

without relief; and, (4) are situated in water depths greater than 200 meters and lie west of 87 

degrees, 30 minutes West longitude. From 1995 through 2000, the U.S. Department of the 

Interior (USDOI), Minerals Management Service (MMS) has granted requests for deepwater 

royalty relief for five fields in the Gulf. In a May 2000 press release, MMS (2000) noted that:

“Today [May 2000] there are approximately 7,600 active leases in the Gulf of 

Mexico, 48 percent of which are in deepwater. Contrast this to 5,600 active 
2

leases in 1992, only 27 percent of which were in deep water regions. By the end 

of 1999, there were 30 producing fields, up 30 percent in 12 months.... Advances 

in deepwater drilling and production technology are as remarkable as the strides 

made in the space industry. Exploratory drilling and production in the western 

and central portions of the northern Gulf of Mexico have steadily increased. 

Deepwater is driving the new millennium.”

The Act has also had an extraordinary effect on bidding for Outer Continental Shelf lease areas. 

For example, Figure 1.1 shows the annual number of active leases in the Gulf since 1994. In 

the early 1990s, there were considerably more active leases in shallow water (i.e., < 200

meters) than in other deepwater depth categories combined. By 1996, these trends began to 

change considerably. In 2001, there were more active leases (3,434) in the deepwater Gulf 

(i.e., > 800 meters) than in shallow waters (3,366). Figure 1.2 shows this same information on 

the basis of active leases, by water depth, as a percent of the total.

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

1994 1995 1996 1997 1998 1999 2000 2001

200-400m

400-800m

>800m

<200m

200-400m 400-800m >800m <200m

Number of Active Leases

Figure 1.1. Active Leases in the Gulf of Mexico by Water Depth.

Source: USDOI, MMS (2002a)
3

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

<200m 200-400m 400-800m >800m

Percent of Total Leases (%)

Figure 1.2. Annual Percent of Total Active Leases in the Gulf of Mexico by Water Depth.

Source: USDOI, MMS (2002a)

Exploring, developing, and producing oil and gas resources from offshore facilities have been a 

logistical challenge since its earliest days in 1947. Oil and gas development and production 

play an important role on the communities surrounding the Gulf of Mexico. These are the 

locations from which offshore operations are staged. Welders, caterers, engineers, roughnecks, 

boat crews, mechanics, helicopter crews, among many others, contribute to the logistical chain 

needed to maintain offshore operations. Regardless of where the exploration and production 

equipment, personnel and supplies are used, at some point, they come from, or through a Gulf 

community. 

According to a recent study conducted on behalf of the Louisiana Mid-Continent Oil and Gas 

Association (LMOGA), there were over 62,511 employees associated with the oil and gas 

extraction, pipeline, and refining portions of the industry in the year 2000 (Scott 2002).

1

 Wages 

associated with these employment opportunities amounted to nearly $3.5 billion. Energy jobs 

and earnings were found in at least 50 of Louisiana’s 64 parishes in 2000. In addition, there 

were 14 parishes where more than 1,000 workers were directly employed in the oil and gas 

industry.

 

1

 Note that these employment figures, and other information associated with this report and cited 

elsewhere, include activities associated with both onshore and offshore activities.
4

Project Scope

The development of deepwater oil and gas resources only adds to the important role that the oil 

and gas industry plays on the coastal communities. Because of its statutory responsibilities, the 

MMS has an ongoing need to understand the role that this infrastructure plays on local

communities. Specifically, MMS must

(1) Produce lease-sale Environmental Impact Statements (EISs) that depict existing, 

OCS-related infrastructure and its future growth and trends;

(2) Make a large number of permitting decisions that consider existing, future, and past 

infrastructure;

(3) Annually update maps that depict infrastructure supporting offshore activities; and,

(4) Guide and monitor long-range planning and development of OCS activities.

MMS executed this project in order to address each of the above issues. This Fact Book is but 

one component of the overall tasks of the project. The Fact Book incorporates data collected as 

part of the GIS database developed for the project. These data were collected in 2000 and 

2001. The purpose of the Fact Book is to describe the existing infrastructure in the GOM and 

how it supports offshore activities. The Fact Book also examines historical data to identify past 

trends and to identify future trends in the construction, use and retirement of OCS-related 

infrastructure.

Eleven major infrastructure categories were identified for this study. These include:

• Platform Fabrication Yards: Facilities in which platforms are constructed and 

assembled for transportation to offshore areas. Facilities can also be used for 

maintenance and storage.

• Port Facilities: Major maritime staging areas for movement between onshore

industries and infrastructure classifications and offshore leases.

• Shipyards and Shipbuilding Yards: Facilities in which ships, drilling platforms, and 

crew boats are constructed and maintained.

• Support and Transport Facilities: Facilities and services that support the offshore 

activities. This includes repair and maintenance yards, supply bases, crew services, 

and heliports. 

• Waste Management Facilities: Sites that process drilling and production wastes 

associated with offshore oil and gas activities.

• Pipelines: Infrastructure that is used to transport oil and gas from offshore facilities 

to onshore processing sites, and ultimately to end users.

• Pipe Coating Yards: Sites that condition and coat pipelines used to transport oil 

and gas from offshore production locations.
5

• Natural Gas Processing Facilities: Sites which process natural gas and separate 

its component parts for the market.

• Natural Gas Storage Facilities: Sites that store processed natural gas for use 

during peak periods.

• Refineries: Industrial facilities that process crude oil into numerous end-use and 

intermediate use products.

• Petrochemical Plants: Industrial facilities that intensively use oil and natural gas, 

and their associated by-products, for fuel and feedstock purposes.

One of the challenges in preparing this Fact Book has been in the categorization and

presentation of information. While the 11 categories presented above seem straightforward, 

they fail to note the important interaction between infrastructure types. Ports, in particular, is an 

infrastructure category for which separating the interactions can be almost impossible.

The interactions between infrastructure types can be highlighted more clearly if they are thought 

more in terms of their functions, relative to offshore activities, than their physical characteristics. 

There are two major functions for most onshore infrastructure types in the GOM region: (1) 

those areas of infrastructure that support oil and gas activities and (2) those areas that are

supported by offshore oil and gas activities.

Figure 1.3 shows the relationship between supporting infrastructure areas and offshore 

activities. For instance, in this figure, we see a number of activities that are staged from 

onshore areas that are vital for offshore operations. An important point from this figure is the 

vital role that ports play as the point of departure to offshore regions.

Figure 1.3. Onshore Support Infrastructure.
6

Supply bases, as well as repair and maintenance yards, usually housed at or very near port 

facilities, are major staging points for moving the significant amounts of equipment and 

materials needed to run an offshore oil and gas operation. Shipyards, on the other hand, are 

important pieces of support infrastructure since many drillships, drilling platforms, and crew 

boats are constructed and maintained at these facilities.

There are other significant pieces of onshore infrastructure that are highly dependent upon 

offshore oil and gas activities as shown in Figure 1.4. These industries facilitate the processing 

and transportation of oil and gas resources to the market. For instance, waste management 

facilities process the waste associated with the production process in offshore areas. 

Refineries, on the other hand, take crude oil, transported to their facilities via pipeline, and 

process it into various petroleum products. Natural gas is typically stored in facilities along the 

Gulf during off-peak periods for use during peak-periods.

Figure 1.4. Onshore Infrastructure Supported by OCS Activities.

The following chapters of this Fact Book discuss each of these critical infrastructure areas and 

their relationship with offshore oil and gas activities. Each chapter outlines:

• Description and Typical Facilities: This section examines the infrastructure in 

question, and provides a description of its unique features. Typical facilities, or 

common characteristics, are also discussed.
7

• Industry Characteristics: This section discusses the industry characteristics

associated with the infrastructure under examination.

• Regulations: This section discusses the salient regulations associated with the 

infrastructure. 

• Industry Trends and Outlook: This section examines the current trends and future 

outlook of infrastructure development in the Gulf.

Also provided, in Appendix I, is a general description of the database and Geographic

Information System (GIS) under this contract as well as a description of queries that can be 

made of the database elements.
9

2.0 PLATFORM FABRICATION YARDS

2.1 Introduction

During the 1920’s and 1930’s, drillers attempted different techniques in their efforts to extract oil 

from Louisiana’s swampy terrain. By 1930, a successful solution was developed, and floating 

vessels containing drilling equipment were introduced. However, the limited technology only 

allowed for use in calm, shallow water without current, waves, tides, and wind. Although it had 

limitations, this seemingly simple concept became the starting point for one of the most

important developments in offshore drilling - the mobile drilling rig. 

G.E. McBride, a Texas Company (now Texaco) employee was quick to further this simple 

concept. His design consisted of using barges as floating vessels that carried a platform for 

derrick and equipment. The vessel was to be towed to the location, sunk on the spot, and 

would act as a fixed foundation for the platform, which would remain above the water. After 

attaining the patent permission of Louis Giliasso, the patent owner for McBride’s concept, Texas 

Company began to construct the world’s first submersible. This project was not met without 

criticism, however. The idea was rejected by many potential customers whose fear was that 

once the vessel had been sunk, it would remain in the mud and be forever lost. Despite 

criticisms, in 1933, the Texas Company named its first submersible ‘Giliasso’, after its inventor. 

The Giliasso spurred new ideas and the Texas Company (as well as others) continued to 

develop new plans concerning oil exploration and production on water. The Giliasso had been 

a technological breakthrough, however, now logistic support was the problem. Once the Texas 

Company discovered oil with the Giliasso, crews had to live in piling-support camps suspended 

over the marsh muck. Drilling mud was hauled 35 miles to the drilling site, and aboveground 

storage was a problem. To meet the need for field storage, three obsolete oil tankers were 

grounded and connected to an old steel schooner, which was used as a loading dock. The oil 

was then lightered to vessels offshore. The problem was finally solved in 1952 with the 

completion of a 135-mile pipeline. However, in the meantime, a number of support industries 

had already arisen and taken their place in the offshore market. 

Since the 1950s, more than 5,500 platforms have been installed in the Gulf of Mexico. Today 

there are more than 3,600 fixed structures at depths of up to 1,700 feet and floating structures 

have reached almost 10,000 ft water depths. Throughout the decades of technological

progress, the fabrication industry along the Gulf Coast has been a principal contributor to the oil 

and gas industry advances and has expanded to handle the construction of structures and

components necessary to continue exploration and production. The industry has grown

significantly – parallel to that of the offshore industry itself. The fabrication corridor includes 

1,000 miles of shoreline from the Texas/Mexico border on the western edge, to Alabama at the 

eastern boundary (Hunt and Gary 2000).

And, as the technology used in the offshore industry advances and changes, so must that of the 

fabrication yard. “Located along an extensive intracoastal waterway system, yet within access 

to the Gulf of Mexico, the industry hosts numerous specialized fabrication yards and facilities. 

For the most part, each yard has a specialty, whether it is the fabrication of separator or

heater/treater skids, the construction of living quarters, the provision of hookup services, or the 

fabrication of jackets, decks and topside modules. While there are large facilities capable of 
10

handling current and next-generation deepwater structures, few facilities have complete

capabilities for all facets of such a project. Even the largest fabrication facilities rely on 

specialized yards, shops, and subcontractors for many of a project's components” (Hunt and 

Gary 2000).” According to a survey conducted by Mustang Engineering of 51 yards, nine have 

single piece fabrication capacity of more than 10,000 tons and 12 indicate a capability to 

fabricate structures intended for water depths exceeding 1,000 ft (Hunt and Gary 2000).

2.2 Description and Typical Facilities

In the early days of offshore drilling, explorers simply fitted a derrick to a barge and towed it to 

their site. Today, four types of offshore rigs are used to drill wildcat or exploration wells

(Australian Institute of Petroleum 2002):

• Submersibles: Submersibles can be floated to shallow water locations then

ballasted to sit on the seabed. However, they are rarely used, mainly because, when 

towing submersibles, the greater the water depth, the greater the uncertainty of 

stability. Also, deeper waters require more space between the platform deck and the 

barge, resulting in an unstable configuration. 

• Jackups: These are usually towed to a location. Their legs are then lowered to the 

seabed and the hull is jacked-up clear of the sea surface. They are used in waters to 

about 160 meters deep.

• Drill ship: These look like ordinary ships but have a derrick on top which drills 

through a hole in the hull. Drill ships are either anchored or positioned with 

computer-controlled propellers along the hull which continually correct the ships drift. 

Often used to drill wildcat wells in deep waters.

• Semi-submersible: Mobile structures, some with their own locomotion. Their 

superstructures are supported by columns sitting on hulls or pontoons which are 

ballasted below the water surface. They provide excellent stability in rough, deep 

seas.

Production Platforms: Once oil or gas is found, the exploratory drilling rig is replaced with a 

production platform, assembled at the site using a barge equipped with heavy lift cranes. 

Platforms vary in size, shape and type depending on the size of the field, the water depth and 

the distance from shore.

Today, offshore platforms play a pivotal role in the development of offshore oil and gas

resources. The purpose of platforms is to house production and drilling equipment and living 

quarters for personnel (for manned platforms). As shown in Figure 2.1, several types of

production systems are used in offshore oil and gas development.2 They vary in size, shape 

and type depending on the size of the field, the water depth and the distance from shore. A 

platform consists of two major components: an underwater part (jacket or tower) and an above 

 

2

 Although some recently developed production systems, such as the floating production system, are 

not platforms in the strict sense, platform-type structures continue to be the staple of the offshore oil and 

gas operations.
11

water part (deck). Other platform components are living quarters, control building, and

production modules.

• Fixed Platform: This is the most commonly used type of production system in the 

U.S. Gulf of Mexico. A fixed platform is a large skeletal structure extending from the 

bottom of the ocean to above the water level. It consists of a metal jacket, which is 

attached to the ocean bottom with piles, and a deck, which accommodates drilling 

and production equipment and living quarters. Fixed platforms are typically installed 

in water depths up to 1,500 feet.

• Compliant Tower: Similar to a fixed platform, however the underwater section is 

not a jacket but a narrow, flexible tower which, due to the flexibility of its structure, 

can move around in the horizontal dimension, thereby withstanding significant wave 

and wind impact. Compliant towers are typically installed in water depth from 1,000 

up to 2,000 feet.

Figure 2.1. Permanent Production Systems on the GOM OCS.

Source: USDOI, MMS (2000a)
12

• Tension and Mini-tension Leg Platforms: These do not have skeletal structures 

extending all the way to the ocean floor. Essentially, this is a semi-submersible 

anchored to the seabed with vertical, taut steel cables or solid pipes. Wellheads can 

be placed on the TLP’s deck, unlike the free-floating platforms (like ships and 

“normal” semi-submersibles). Tension leg platforms can be used in different depth 

ranges, up to 4,000 feet. 

• SPAR Platform: This platform consists of a large vertical hull, which is moored to 

the ocean floor with up to twenty lines. On top of the hull sits the deck with

production equipment and living quarters. Presently, SPAR platforms are used in 

water depth up to 3,000 feet; however, SPAR technology allows installations in

waters as deep as 7,500 feet.

• Floating Production System: This system consists of a semi-submersible unit 

which is kept stationary either by anchoring with wire ropes and chains or by the use 

of rotating thrusters, which self propel the semi-submersible unit. Floating production 

systems are suited for deepwater production, in depths up to 7,500 feet.

• Subsea System: A subsea system consists of a single subsea well or several wells 

producing either to a nearby platform or to a distant production facility through a 

pipeline and manifold systems. Currently, subsea systems are used in water depths 

exceeding 5,000 feet.

• Floating Production, Storage, and Offloading (FPSO) System: This system 

consists of a large vessel, which houses production equipment. It collects oil from 

several sub-sea wells, stores it, and periodically offloads it to a shuttle tanker. FPSO 

systems are particularly useful in development of remote oil fields where pipeline 

infrastructure is not available. 

While recent trends in platform fabrication have been moving towards more specialization, there 

are still a number of large, comprehensive platform fabrication facilities (or yards) in the Gulf. 

For instance, J. Ray McDermott's Morgan City fabrication yard is the largest facility of its kind 

and one of the most advanced. It has 287 developed acres producing structures, facilities and 

components of every size. The Morgan City fabrication services include platform jackets 

(bases), deck sections, deck facilities; production modules, drilling modules and quarters

modules; oil and natural gas processing, transfer and storage facilities; floating platforms and 

production facilities; offshore floating terminals; subsea production facilities; control systems for 

subsea production wells; process piping; process vessels; caissons (well protectors); and rig 

repair.

Other large, comprehensive fabrication yards include Gulf Island Fabrication, Inc. in Houma, 

Louisiana. Gulf Island has 250 acres devoted to fabrication facilities. Its services include: 

structural steel fabrication (jackets, decks, pilings, and piping); blasting and coating; hydrostatic 

and pneumatic testing and multiple load out capabilities. 

These large integrated facilities typically span a broad, continuous geographic area. The yards 

are typically gated for security and safety reasons. These yards have to be large to handle the 

massive size of the platforms that are under construction. Consider that Shell Offshore’s
13

Bullwinkle platform, the largest of its kind, is 1,353 feet tall. The Sears Tower, the largest 

building in North America, is 1,450 feet – a mere 97 feet taller than Bullwinkle.

A typical facility will be composed of numerous large buildings that open into large outdoor work 

areas. These buildings allow for construction and fabrication activities to be conducted at all 

hours of the day, and during inclement weather. These sites also typically have a number of 

“out-buildings” which in many instances are trailers or portable buildings. These out-buildings 

service as administrative areas and project management offices. Their modularity allows them 

to be moved near particular projects for close supervision and oversight on projects.

Sites often contain large amounts of stacked tubing, piping, steel beams and girders, and old 

platforms for re-use or re-furbishing. Usually a large canal and dock are attached to the yard so 

that the final product can be removed from the yard, and towed to a major waterway for

transportation to its final destination which could be the GOM or other oil and gas producing 

areas of the world.

2.3 Industry Characteristics

Platforms are fabricated onshore, and then towed to an offshore location for installation. 

Facilities where platforms are fabricated are called platform fabrication yards. Production

operations at fabrication yards include cutting and welding of steel components, construction of 

living quarters and other structures, as well as assembling platform components. Fixed platform 

fabrication can be subdivided into two major tasks: jacket fabrication and deck fabrication.

• Jacket Fabrication: The jacket is constructed by welding together steel plates and 

tubes to form a tower-like skeletal structure. Because the height of a jacket is

several hundred feet, jackets are made lying horizontally on skid runners. Once the 

jacket is completed, it is pulled over, maintaining the same horizontal position, to a 

barge that transports it to an offshore location where the jacket is installed. Along 

with the jacket is the construction of smaller ancillary structures such as pile guides, 

boat landings, walkways, buoyancy tanks, handrails, etc. These structures are

attached to the jacket while it is still in vertical position.

• Deck Fabrication: The deck is fabricated separately from the jacket. A typical deck 

is a flat platform supported by several vertical columns (deck legs). The deck

provides the necessary surface to place production equipment, living quarters, and 

various storage facilities. Once the deck fabrication is completed, it is loaded onto a 

barge and transported to the site of the platform, where it is lifted by derrick barges 

and attached to the already installed jacket. 

Location of platform fabrication yards is tied to the availability of a navigable channel sufficiently 

large to allow towing of bulky and long structures such as offshore drilling and production 

platforms. Thus, platform fabrication yards are located either directly on the coast of the Gulf of 

Mexico or inland, along large navigable channels, such as the Intracoastal Waterway. Average 

bulkhead depth for water access for fabrication yards in the Gulf is 15-20 feet. 

Due to the size of the fabricated product and the need to store a large quantity of materials such 

as metal pipes and beams, fabrication yards typically occupy large areas, ranging from just a 

few to several hundred acres. Typical fabrication yard equipment includes lifts and cranes,
14

various types of welding equipment, rolling mills, and sandblasting machinery. Besides large 

open spaces required for jacket assembly, fabrication yards also have covered warehouses and 

shops. Because the construction of platforms is not likely to be standardized, an assembly-line 

approach is unlikely and most fabrication yards work on projects one at a time. Once a platform

is complete, it is towed to its offshore location, and then work on the new platform commences. 

The number of employees between fabrication yards may vary from less than a hundred to 

several thousand. Relative to the international market, Gulf coast yards have a low number of 

employees (Hunt and Gary 2000). Hunt and Gary (2000) reported that only nine yards had a 

work force of more than 1,000.

Platform fabrication is not a mass production industry; every platform is custom built to meet the 

requirements of a specific project. This feature has given rise to the great degree of

specialization in the platform fabrication. There are no two identical fabrication yards; most

yards specialize in the fabrication of a particular type of platform or platform component. 

Examples of specialization include construction of living quarters, provision of hook-up services, 

and fabrication of jackets and decks. According to a published 1999 survey of fabrication yards 

in the Gulf, out of 50 yards, 23 fabricate jackets, 15 fabricate decks, 29 fabricate modules, 22 

fabricate living quarters, and 20 fabricate control buildings (Gary and Nutter 2000). Despite the 

specialization of these yards, most facilities do include:

• steel stockyards and cutting shops which supply and shape steel; 

• assembly shops which put together a variety of components such as deck sections, 

modules, and tanks; 

• paint and sandblasting shops; 

• drydocks which work on small vessels; 

• piers which work on transportation equipment and the platform components that are 

mobile and can be transported onto barges; and 

• pipe and welding shops.

Despite a large number of platform fabrication facilities in the Gulf, only a few facilities can 

handle large-scale fabrication. According to a 1999 survey of fabrication yards, nine yards have 

single piece fabrication capacity over 100,000 tons and twelve have capacity to fabricate

structures for water depth over 1,000 feet (Gary and Nutter 2000). Only a few yards fabricate 

structures other than fixed platforms: one fabricates compliant towers (J. Ray McDermott, Inc.’s 

Morgan City yard located in Amelia, Louisiana), and two fabricate tension leg platforms (Gulf 

Island fabrication Inc., in Houma, Louisiana and Friede Goldman Offshore in Pascagoula,

Mississippi).

Another important characteristic of the industry is a high degree of interdependency and

cooperation among the fabrication yards. Because offshore platforms, particularly the ones

destined for the deep water, are such complex engineering projects, most facilities do not have 

technical capabilities to complete an entire project “in-house,” without subcontractors and

specialized yards.

Many production companies are starting to stray away from the traditional onshore yards. 

There are numerous offshore structures that support the main production platforms that are 

interconnected via bridges. The Freeport-McMoran Resource Partners Platform includes
15

thirteen different connecting bridges - the largest of its kind in the Gulf of Mexico (J. Ray 

McDermott 2000). Bridges connect mobile and stationary structures, like barges. Barge 

fabrication has evolved to carry multi-deck units. The barges are “spread-moored with six 

anchor chains at each corner” (Naklie 1998). The multi-deck units house production equipment 

and other submersible pumps and tanks, living quarters, mechanical shops and warehouses 

which traditionally use onshore fabrication yards. Having shops offshore provide obvious 

advantages; operators do not have to wait for spare parts from onshore sites.

2.4 Regulations

All platforms located in the OCS must be designed, fabricated, installed, used, inspected and 

maintained to assure their structural integrity for the safe conduct of operations at specific 

locations. Applications for platform approval are filed in accordance with 30 CFR 250.901:

• Applications for all new platforms or major modifications must be submitted in 

triplicate and contain the following information:

- General platform information including the platform designation, lease number, 

area name, and block number; Longitude and latitude coordinates, Universal 

Transverse Mercator grid-system coordinates, state plane coordinates in the

Lambert or Transverse Mercator Projection system, and a plat drawn to a scale of 

1 inch = 2,000 feet showing surface location of the platform and distance from the 

nearest block lines;

- Drawings, plats, front and side elevations of the entire platform, and plan views 

that clearly illustrate essential parts, i.e., number and location of well slots, design 

loadings of each deck, water depth, nominal size and thickness of all primary loadbearing jacket and deck structural members, and nominal size, makeup, thickness, 

and design penetration of piling;

- Corrosion protection or durability details which consist of the corrosion-protection 

method; expected life; and durability criteria for the submerged, splash, and

atmospheric zones;

- A summary of environmental data, which has a bearing on the platform's design, 

installation, and operation, e.g., wave heights and periods, current, vertical

distribution of wind and gust velocities, water depth, storm and astronomical tide 

data, marine growth, snow and ice effects, and air and sea temperatures;

- Foundation information including a geotechnical investigation report; and,

- Structural information including the design life of the platform and the basis for 

such determination.

The platform lessee evaluates characteristic environmental conditions associated with

operational functions to be performed. Factors such as waves, wind, currents, tides,

temperature, and the potential for marine growth on the structure are considered. 
16

In addition, a program has been established by the MMS to assure that new structures are 

designed, fabricated, and installed using standardized procedures to prevent structural failures. 

This program facilitates review of such structures and utilizes third-party expertise and technical 

input in the verification process through the use of a Certified Verification Agent. All platforms 

are inspected during the construction process considering the following:

• All pile-supported and gravity platforms covered by this subpart must be inspected 

during the construction phase. The phases of construction subject to inspection 

include material manufacture, fabrication, loadout, transportation, positioning,

installation, and final field erection.

• Inspections during construction are to verify that the platform is constructed in

accordance with the approved construction plan. Any unusual or innovative

application of materials or methods of construction not adequately covered by the 

requirements of this section must receive special attention during compliance

inspections relevant to its effect on the integrity of the platform. 

• If construction inspection results reveal that materials, procedures, or workmanship 

deviate significantly from the approved design, remedial action must be taken.

• The origin of materials used in the platform and the results of relevant material tests 

for all significant structural materials must be retained and made readily available for 

inspection by MMS representatives during all stages of construction. 

• Records shall be kept of the locations throughout the platform of the various heat 

numbers for such materials.3

After installation, all platforms in the OCS are inspected periodically in accordance with the 

provisions of API RP 2A, Section 14, Surveys. Use of an inspection interval which exceeds 5 

years requires prior approval by the Regional Supervisor. Proper maintenance needs to be 

performed to assure the structural integrity of the platform as a workbase for oil and gas 

operations. A report must be submitted annually on November 1 to the Regional Supervisor 

stating which platforms have been inspected in the preceding 12 months, the extent and area of 

inspection, and the type of inspection employed, i.e., visual, magnetic particle, ultrasonic testing. 

A summary of the testing results is submitted indicating what repairs, if any, were needed and 

the overall structural condition of the platform.4

2.5 Industry Trends and Outlook

Over the whole history of its existence, the ups and downs of the platform fabrication industry 

have been closely tied to the fortunes of the oil and gas industry. Drilling and production 

activities are sensitive to the changing prices for oil and gas. This sensitivity, in turn, is

translated into “boom and bust” cycles for the fabrication industry, when a period of no work 

follows a period of more fabrication orders than a yard can complete. In order to shield 

themselves from the volatility inherent in the oil and gas industry, platform fabrication yards in 

the U.S. Gulf of Mexico have started to implement various diversification strategies. These 

 

3

30 CFR 250.911

4

30 CFR 250.912
17

diversification strategies, coupled with the new challenges brought about by the deepwater oil 

and gas exploration and development, are significantly changing the industry.

In order to utilize the existing equipment and to keep the highly-skilled workforce in the periods 

with no fabrication orders, many fabrication yards are expanding their operations into areas 

such as maintenance and renovations of drilling rigs, fabrication of barges and other marine 

vessels, dry-docking, and survey of equipment. These projects, although much smaller in scale 

and scope than platform fabrication, nevertheless allow the yards to survive the recessions.

Another avenue of diversification is the pursuit of international work in platform fabrication. The 

U.S. Gulf of Mexico fabrication yards have a double advantage of great experience in fabrication

work and good climatic conditions, allowing for year-round operations.

Companies have also developed new products like offshore management software and

company-specific systems for managing and monitoring offshore sites onshore. New and 

improved platforms or platform upgrades and revamps complement many of the systems and 

software. The MinDOC Deepwater Drilling and Production System includes a simple template 

of “tubes and boxes” (MinDoc, L.L.C. 2000). This cost-efficient system can be assembled and 

installed in one piece, “without the need of offshore mating or derrick barge assistance at

uprighting.” Moreover, the components can be modified for different deepwater depths and 

reused towards different production sites.

There are a number of new software products that facilitate an accurate exploration and 

production activity. Many, like the product by Multi Products Co., called WellTest are

compatible to MS Excel, Windows and other existing data managing software. WellTest

provides the operator with the number of cycles per day and the amount of liquids produced 

with the complementing plunger (Lee et al. 2000). It provides travel time per cycle, plunger fall 

time based on plunger type, number of cycles per day, and production scenarios for various 

schemes. Kenonic Controls has created MaxOil management software which manages realtime well production information for more accurate analyses by operators. It takes data from 

various sources and combines events with well-specific engineering analysis to correct nonflowing conditions which lead to production loss and equipment damage. It is one of the

software products that is useful for remote fields (Lea et al. 2000).

One problem the platform fabrication industry experienced in the past was the lack of skilled

workers at the beginning of an upswing in the business cycle because the skilled labor had 

already migrated to other jobs during the downswing. Having learned from the past mistakes, 

some fabrication companies have organized technical training programs in the local

communities. A locally-trained workforce provides a readily available pool of skilled labor for the 

fabrication yards. Other companies have found a solution to the workforce problem through the 

acquisition of several individual fabrication yards located within the single commuting area. This 

allows companies to dispatch their personnel to several yards to accommodate the existing 

need for workers at any given time.

With respect to the deepwater development, the challenges for the fabrication industry stem 

from the greater technical sophistication and the increased project complexity of the deepwater 

structures, such as compliant towers and floating structures. The needs of the deepwater 

projects are likely to result in two important trends for the fabrication industry. The first is the 

increasing concentration in the industry, with respect to the deepwater projects. As technical 
18

and organizational challenges continue to mount, it is expected that not every fabrication yard 

will find adequate resources to keep pace with the demands of the oil and gas industry. The 

second trend is the closer integration, through alliances, amalgamations, or mergers, among the 

fabrication yards and engineering firms.

With respect to the structure of the platform fabrication industry, it is undergoing a period of 

restructuring, which is characterized with transformation from privately to publicly held

companies on the one hand, and with the consolidation of the industry through mergers and 

acquisitions. While implications of these changes are yet to be understood, it is clear that their 

impact will be significant.

Inventory: Table 2.1 provides results of a 2001 inventory of platform fabrication yards 

conducted as part of development of this Fact Book and GIS database. Of the 43 facilities 

inventoried, 31 were located in Louisiana, 7 in Texas, 4 in Mississippi, and 1 in Alabama. Land 

area covered by the facilities ranged from a few acres to several hundred acres.

Expansion of Offshore Drilling: The offshore drilling industry has come a long way since it 

installed the first subsea wellhead in 1961. The Gulf represents an expanding frontier with 

extraordinary growth – especially of deepwater – in oil and gas industry activity over the past 7 

years. For instance, at the end of 2001, there were 51 producing fields in the deepwater Gulf; a 

38 percent increase from the year before. In just a year (between 2000 and 2001), “remarkable” 

achievements have been made, for example (USDOI, MMS 2002a):

• The number of drilling rigs working in deepwater increased from 28 to 43; 

• The number of ultra-deepwater (> 5,000 ft) capable rigs increased from 18 to 26 (44 

percent) and the number of ultra-deepwater wells increased from 37 to 59 (59 percent);

• There was a 59 percent increase in the number of producing deepwater fields;

• Deepwater oil production is rapidly approaching the all-time shallow-water oil production 

record established in 1971; and,

• New deepwater drilling added over 4 billion barrels of oil equivalent (BOE), a 49 percent 

increase, to the Gulf of Mexico oil and gas inventory.
19

Table 2.1

Platform Fabrication Facilities in the Gulf (2001)

 Name Owner City State Size (ac) Platform

Type

Mobile Yard Atlantic Marine Alabama Shipyard Mobile AL 680 Unknown

Gulfport Yard Friede Goldman Offshore Gulfport MS 110 Unknown

Pascagoula East Yard Friede Goldman Offshore Pascagoula MS 180 FPSO

Pascagoula West Yard Friede Goldman Offshore Pascagoula MS 13 FPSO

Pascagoula Yard Ingalls Shipbuilding Pascagoula MS 800 FPSO

 Abbeville (Port of Vermilion) Yard Gulf Coast Marine Fabricators Abbeville LA 7 FIXED

Abbeville Yard Acadian Contractors Abbeville LA 6.5 FIXED

Abbeville Yard Mar-Con, Inc. Delcambre LA 10 FIXED

Amelia Yard J. Ray McDermott, Inc. Amelia LA 589 CT

Baldwin Yard Superior Fabricators, Inc. Baldwin LA 19.5 FIXED

Belle Chasse Yard Omega Service Industries, Inc. Belle Chasse LA 18.5 FIXED

Delcambre Yard Shaw Bagwell Delcambre LA 60 FIXED

East Yard Bay Offshore Ltd. East Yard Amelia LA 6 FIXED

Gibson Yard Max Welders, Inc. Gibson LA 27 FIXED

Harvey Yard Chet Morrison Contractors, Inc. Houma LA 17 FIXED

Harvey Yard Dynamic Industries, Inc. Harvey LA 3.7 FIXED

Harvey Yard Houma Industries Harvey LA 3 FPSO

Harvey Yard Metal Building Products Harvey LA 1.8 FPSO

Harvey Yard Production Mgmt Industries, Harvey LA 9.5 FIXED

Harvey Yard Southport, Inc. Harvey LA Unknown

Houma Yard Chet Morrison Contractors, Inc. Harvey LA 7 FIXED

Houma Yard Dolphin Services, Inc. Houma LA 23 FIXED

Houma Yard Gulf Island Fabrication, Inc. Houma LA 582 FIXED

Houma Yard Offshore Specialty Fabricators, Inc.Houma LA 52 FIXED

Houma Yard Sigma Industries, Inc. Houma LA 17.2 Unknown

Ingleside Yard Offshore Specialty Fabricators, Inc.Houma LA 58 FIXED

Mosby Unit Bay Offshore Ltd. Mosby Unit Belle Chasse LA 17.5 FIXED

New Iberia Yard Allen Process Systems New Iberia LA 25 FPSO

New Iberia Yard Dynamic Industries, Inc. New Iberia LA 44 FIXED

New Iberia Yard L-Con Marine Fabricators New Iberia LA 18 FIXED

New Iberia Yard Natco New Iberia LA 20 FPSO

New Iberia Yard Omega Service Industries, Inc. New Iberia LA 62.5 FIXED

New Iberia Yard Unifab International, LLC New Iberia LA 170 FIXED

Seawolf Group Bay Offshore Ltd. West Yard New Iberia LA 15 FIXED

South Louisa Yard Twin Brothers Marine Morgan City LA 57 FIXED

West Yard Bay Offshore Seawolf Group Amelia LA 4 FIXED

 Brownsville Yard Amfels, Inc Brownsville TX 200 FPSO

Channelview Yard Delta Engineering Corporation Channelview TX 31 FIXED

Galveston Yard First Wave Newpark Shipbuilding Galveston TX 112 FIXED

 Greens Bayou Yard Brown & Root Energy Services Houston TX 184.9 FIXED

 Ingleside Yard Aker Gulf Marine Ingleside TX 400 FPSO

 Ingleside Yard State Service Co., Inc. Ingleside TX 14.5 FIXED

Turbofab Facility Solar Turbine Inc. Channelview TX 50 Unknown

Source: Acadian Consulting Group, Inc., 2001; The Louis Berger Group, Inc. 2001
20

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

leasing, drilling, and production. According to USDOI, MMS (2002a), in 2001 there are 

approximately 7,400 active leases in the Gulf of Mexico OCS, 53 percent of which are in

deepwater. 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 43 rigs drilling in deepwater in 

2001, up from only 3 rigs in 1992 and 28 rigs in 1999. Likewise, deepwater oil production rose 

over 800 percent and deepwater gas production increased about 1,500 percent from 1992 to 

2001 (USDOI, MMS 2002a). 

New advances in technology are also stimulating investment in the Gulf. In May, 2001, the 

MMS announced that Unocal had set a new world record for drilling in deep water. An 

exploration well for oil and gas was drilled in 9,743 feet of water in Alaminos Canyon Block 903, 

less than 4 miles from the U.S.-Mexico boundary line. “[T]he number of wells being drilled in the 

so called ultra-deep water – those in 5,000 feet of water or greater – continues to grow 

significantly. Currently, there are ten wells being drilled in water depths of 5,000 feet or greater” 

(USDOI, MMS 2001a). The companies operating the ten wells and the water depths are

displayed in Table 2.2.

Table 2.2

Water Depth Records

Operator Water Depth 

(ft)

Union Oil Co. of California 9,743

Marathon Oil Company 7,742

BP Exploration & Oil Inc. 6,960

BP Exploration & Oil Inc. 6,612

Burlington Resources Offshore 6,308

Murphy Exploration & Production 5,881

Dominion Exploration & 

Production

5,610

Vastar Resources Inc. 5,422

Amoco Production Company 5,180

Shell Deepwater Production Inc. 5,150

Source: USDOI, MMS (2001a) 
21

3.0 PORT FACILITIES

3.1 Introduction

Ports play a vital role in the support of offshore oil and gas exploration and production activities

as well as the maritime industry as a whole. The relationship between the offshore industry and 

port facilities in the Gulf is unique in that the offshore industry relies heavily on ports with 

services tailored to its specific needs. This is explained later in the chapter with the discussion 

of support services such as offshore support vehicles, shipbuilding and repair facilities,

fabrication yards, and supply bases. In general, port facilities can include waterways for

shipping, wharves, piers, docks, and warehouses. Port services include the transfer and 

exchange of cargo and passengers between water and landside transportation modes

(including rail, pipeline, truck, etc.). Ports handle a variety of cargo, including bulk, or loose 

cargo, break bulk cargo in packages such as bundles, crates, barrels and pallets, liquid bulk 

cargo such as petroleum, dry bulk such as grain, and general cargo in steel boxes called 

containers. 

Leading commodities shipped for domestic and foreign trade through U.S. ports include

(American Association of Port Authorities 2002a): 

• Petroleum and petroleum products – oil, gasoline;

• Chemicals and related products – fertilizer;

• Coal – bituminous, metallurgical, steam;

• Food and farm products – wheat and wheat flour, corn, soybeans, rice, cotton,

coffee;

• Crude materials - forest products, wood, and wood chips; soil, sand, gravel, rock, 

and stone; and, iron ore/scrap

Manufactured products including: 

• Automobiles, automobile parts and machinery; and

• Clothing, shoes, electronics, toys.

Figure 3.1 illustrates the principal commodity groups transported on U.S. waters for 2001. 

Almost 44 percent of total waterborne commerce (both foreign and domestic) is attributed to 

petroleum and petroleum products. This is three times more commerce transported than any 

other commodity group – crude materials comprise the second largest group with 14.8 percent. 

If looking only at foreign commerce (waterborne import) the petroleum and petroleum products 

category is even higher, at 50.5 percent. This is five times higher than the next category of 

crude materials at 10.4 percent (Institute for Water Resources 2001).
22

There are two major types of port facilities; 1) deep-draft seaports and, 2) inland river and 

intracoastal waterways port facilities. Deep-draft seaports are ports that mostly accommodate 

ocean going vessels, and are most likely to serve and supply offshore drilling platforms. Deepdraft seaports are also more likely to be publicly owned and operated. Inland ports, however, 

are located on rivers or intracoastal waterways, and are mostly privately owned – 87 percent of 

inland facilities are privately owned. More than 1,800 river terminals are located in 21 states 

within the U.S. These ports are unique in that although they have shallow water depths of 14 

feet or less, they are less concentrated geographically and provide almost limitless access 

points to the waterways. “Overall, there are more inland facilities located outside traditional port 

boundaries than within. Terminal siting on the inland waterways is less constrained than coastal 

ports, which provides greater flexibility to the users in determining the location of plants

requiring water access” (Maritime Administration 1999). Such inland terminals, abundant in 

South Louisiana, many along the Mississippi especially between New Orleans and Baton 

Rouge, and Southeastern Texas, have become increasingly important for the offshore industry. 

Places where vessels dock are called berths. Berths can be specialized to serve specific types 

of freight and passenger transfers. For example, berths may be designed to handle

containerized cargo, dry and liquid bulk cargo, automobiles and other cargo that can roll-on/rolloff vessels, and general cargo. Passenger berths handle ferries or large cruise vessels. As of 

1997, 484 terminals on the Gulf Coast contained 786 berths (this includes both privately and 

publicly owned facilities) (Maritime Administration 1999). Many of the berths in ports on the Gulf 

Coal

12.7%

Petroleum & 

Petroleum 

Products

43.9%

Crude Materials

14.8%

Primary 

Manufactured 

Goods

5.7%

Food & Farm 

Products

11.8%

All Others

3.9%

Chemicals & 

Related 

Products

7.1%

Figure 3.1. Principal Commodity Groups Carried by Water (2001) (percentage of tons).

Source: Institute for Water Resources (2001)
23

Coast are specialized to service the over 4,000 offshore drilling platforms in place to support 

offshore mineral development. 

Table 3.1 shows the location of the major seaport facilities by coastal region. Twenty-eight 

states contain coastal ports (including those located on the Great Lakes). The largest number 

of terminals and berths are located in the Gulf States (484 and 786, respectively, in 1997), 

representing 25.3 percent of all U.S. terminals and 24.9 percent of all U.S. berths.

3.2 Description and Typical Facilities

Offshore exploration and production facilities need services that can only be supplied at nearby 

ports and local communities. Such services as repair and maintenance of supply vessels,

fabrication yards, supply bases and companies supplying crew services will be found in ports 

nearest to offshore drilling operations. Other support facilities or services include ships’

chandlers, stevedoring, warehousing and helicopter pads. 

Offshore Support Operations: Any functioning offshore oil and gas production operation 

requires frequent deliveries and pick-ups of personnel, supplies, and materials to and from 

offshore platforms. The large scale of operations in the GOM has led to the development of a 

specialized fleet of vessels known as “Offshore Support Vessels” (OSV). 

OSVs are required in every stage of the offshore drilling process. For instance, during the 

development process, operating companies may invite tenders to supply the assets and

services they require, such as the drilling rigs and support vessels needed to put the particular 

type of rig required on location and supply the rig during its drilling campaign. In some cases, 

Table 3.1

U.S. Ports Handling More Than 10 Million Tons in 1997

Coastal Region

Number of 

Terminals1

Percent of 

Total

Number of 

Berths

Percent of 

Total

North Atlantic 421 22.0 761 24.1

South Atlantic2197 10.3 349 11.0

Gulf 484 25.3 786 24.9

South Pacific3223 11.6 414 13.1

North Pacific4249 13.0 365 11.6

Great Lakes 340 17.8 483 15.3

Total 1,914 100.0 3,158 100.0

Notes: 

1. Includes those commercial cargo handling facilities with a minimum depth alongside of 25 

feet for coastal ports and 18 feet for Great Lakes ports.

2. Includes Puerto Rico and the U.S. Virgin Islands.

3. Includes Hawaii.

4. Includes Alaska.

Source: Maritime Administration (1999)
24

the tender will require the offshore support company to design and build a support vessel to 

particular specifications in order to meet the requirements of the exploration or production 

project (Swire Pacific Offshore 2003).

In addition to the requirement for support vessels during exploration, support vessels are also 

needed to assist in the construction phase of the development of a field, including the supply 

and installation of platforms, the laying of pipelines to shore-based storage facilities and the 

installation of associated offshore loading facilities. Once such infrastructure is in place, there is 

a continuing requirement for the transportation of food, stores, personnel and maintenance 

equipment to the platforms.

Up until the mid 1950s, offshore drilling units were supported by vessels which were not

specially designed for offshore supporting roles, such as converted fishing vessels or tugs. 

However, as rigs increased in size and began to operate in deeper waters and drill to greater 

depths, special purpose support vessels began to be designed and built. Today, OSVs are 

highly specialized and can be described by a number of categories. The following is a list of 

categories of types of OSVs as listed by the publication, Offshore Support Vessels of the World,

published by OPL.

• Accommodation Units 

• Anchor Handling Tug Supply Vessels (AHTSs) 

• Anchor Handling Tugs (AHTs) 

• Cable Lay Vessels 

• Deck Barges 

• Decommissioning Vessels 

• Derrick Barges 

• Diving Support Vessels (DSVs) 

• Dredgers 

• Drilling Tenders 

• Escort Tugs and Floating Storage Units (FSUs) 

• Heavy Lift Vessels and Barges 

• Hydrographic Survey Vessels 

• Jacket Launch Barges 

• Jack-up Drilling Units (JUs) 

• Multi-function Service Vessels (MSVs) 

• Pipe Bury Barges 

• Pipe Carriers 

• Pipe Laying Barges 

• Platform Supply Vessels (PSVs) 

• Pontoon Barges 

• Salvage Tugs 

• Seismic Survey Vessels 

• Semi-submersible Drilling Units 

• Shuttle Tankers 

• Standby Vessels 

• Supply Vessels 

• Transportation Barges 

• Well Stimulation Vessels 
25

According to the USACE Navigation Data Center, in 2000, there were 1,155 registered vessels 

classified as OSV with bases in several ports in the five Gulf Coast states. A large number of 

bases are located inland and are not associated with traditional port facilities. The remaining 

vessels, however, are located at ports – indicating the importance these ports play in serving as 

offshore staging areas. Altogether there are 91 bases on the Gulf Coast; however, most of the 

bases (53) host 4 OSVs or less. Table 3.2 lists all the ports/bases with at least 5 OSVs and 

Figure 3.2 shows the geographical distribution of OSV bases in the Gulf.

Figure 3.2. Distribution of OSV Bases in the Gulf (2000).
26

Table 3.2

Principal Offshore Support Vehicle Bases for the Oil and Gas Industry in the Gulf of 

Mexico (2000)

Rank State Base Name Number of 

OSVs

Percent of 

Total

Cumulative 

Percent

1 LA MORGAN CITY 190 16.5% 16.5%

2 LA HOUMA 117 10.1% 26.6%

3 LA NEW IBERIA 105 9.1% 35.7%

4 LA FOURCHON 88 7.6% 43.3%

5 LA VENICE 52 4.5% 47.8%

6 LA CAMERON 39 3.4% 51.2%

7 LA NEW ORLEANS 32 2.8% 53.9%

8 LA INTRACOASTAL CITY 31 2.7% 56.6%

9 TX GALVESTON 31 2.7% 59.3%

10 LA GALLIANO 29 2.5% 61.8%

11 LA BROUSSARD 27 2.3% 64.2%

12 LA GOLDEN MEADOW 26 2.3% 66.4%

13 LA BELLE CHASSE 21 1.8% 68.2%

14 TX SABINE PASS 21 1.8% 70.0%

15 LA LAROSE 18 1.6% 71.6%

16 LA PATTERSON 18 1.6% 73.2%

17 TX FREEPORT 18 1.6% 74.7%

18 TX ROCKPORT 16 1.4% 76.1%

19 LA CHALMETTE 14 1.2% 77.3%

20 LA LOCKPORT 14 1.2% 78.5%

21 LA ST. ROSE 14 1.2% 79.7%

22 LA CUT OFF 13 1.1% 80.9%

23 LA AMELIA 12 1.0% 81.9%

24 LA DULAC 12 1.0% 82.9%

25 LA UNION 12 1.0% 84.0%

26 TX RIVIERA 11 1.0% 84.9%

27 LA CHAUVIN 9 0.8% 85.7%

28 LA GRAND ISLE 8 0.7% 86.4%

29 LA HOPEDALE 8 0.7% 87.1%

30 LA DELCAMBRE 7 0.6% 87.7%

31 LA LEEVILLE 7 0.6% 88.3%

32 LA BURAS 6 0.5% 88.8%

33 AL BAYOU LA BATRE 5 0.4% 89.3%

34 AL THEODORE 5 0.4% 89.7%

35 LA KENNER 5 0.4% 90.1%

36 MS PASCAGOULA 5 0.4% 90.6%

37 TX ARANSAS PASS 5 0.4% 91.0%
27

Bases located at Louisiana ports account for 86 percent of all Gulf OSVs, Texas ports host 10 

percent of the bases, while the remaining 4 percent (just 36 vessels) are associated with

Alabama, Mississippi, and Florida ports. All five major OSV bases are located in Louisiana: 

Venice, Fourchon, Houma, Morgan City, and New Iberia. These five ports account for almost 

half of all OSV bases in the Gulf.

Shipbuilding and Repair: Shipyards and repair facilities form an important part of the

infrastructure in which ships, barges, vessels and drilling platforms are designed, built and 

repaired. According to the Maritime Administration (MARAD), there are at least 35 major 

shipbuilding and repair bases located on the Gulf Coast (Table 3.3). 

Table 3.3

Major U.S. Shipbuilding and Repair Bases (October 1998)

East 

Coast

Gulf 

Coast

West 

Coast

Great 

Lakes

NonContiguousTotal by 

Type

Shipbuilding 5 8 3 3 0 19

Repair w/Dry -dock 13 8 2 2 3 33

Topside Repair 10 19 2 2 1 40

Total (By Coast) 28 35 7 7 4 92

Source: Maritime Administration (1999) 

Based on an inventory conducted as part of the development of a GIS database for this project, 

we recorded 162 shipbuilding and repair facilities of various sizes located within the Gulf region 

which support the oil and gas industry. Eighty-two facilities are located in Louisiana, 35 in 

Texas, 17 in Mississippi, 15 in Florida, and 13 in Alabama.

A shipbuilding facility can consist of a number of various structures depending on the size of the 

facility and the type of vessel it is designed to handle. Nineteen facilities in the U.S. comprise 

the “Major Shipbuilding Base” (MSB). These yards are typically found on or near deep channels 

allowing them to serve larger deepwater vessels. “The MSB includes shipyards having at least 

one shipbuilding position consisting of an inclined way, a launching platform, or a building basin 

capable of accommodating a vessel of at least 122 meters in length. With few exceptions, 

these shipbuilding facilities are also major repair facilities with dry-docking capability” (NOAA 

2002). Second tier shipyards, comprised of small- or medium-sized facilities, engage primarily 

in the construction of vessels for use on the inland and coastal waterways as well as for foreign 

markets. Shipbuilding and repair and maintenance yards are discussed further in Chapters 4 

and 5, respectively.

Fabrication Yards: As discussed in Chapter 2, offshore drilling platforms are a fundamental 

component in the development and production of offshore oil and gas resources. Not only do 

platforms house the drilling equipment, but also the staff needed to run this machinery. Before 

being installed at an offshore location, platforms are constructed or fabricated onshore at a 

facility called a platform fabrication yard. Production operations at fabrication yards include 

cutting and welding of steel components, construction of living quarters and other structures, as 
28

well as assembling platform components. The yards occupy large areas with equipment 

including lifts and cranes, welding equipment, rolling mills, and sandblasting machinery. 

The location of these fabrication yards is directly tied to the availability of a large enough 

channel that will allow the towing of these bulky and long structures. The average bulkhead 

depth needed for water access to fabrication yards in the Gulf is 15-20 feet. A fabricator must 

also consider other physical limitations such as the ability to clear bridges and navigate tight 

corners within channels. Thus, platform fabrication yards must be located at deep-draft 

seaports or along the wider and deeper of the inland channels. “The fabrication corridor

includes 1,000 miles of shoreline from the Texas/Mexico border on the western edge, to 

Alabama at the eastern boundary. Located along an extensive intracoastal waterway system, 

yet within access to the Gulf of Mexico, the industry hosts numerous specialized fabrication 

yards and facilities” (Hunt and Gary 2000). 

Because facilities must be so large to carry out the construction of these enormous structures, 

few facilities have complete capabilities for all facets of a fabrication project. Generally, each 

yard has a specialty which can include: fabrication of separator or heater/treater skids; the 

construction of living quarters; the provision of hookup services; or the fabrication of jackets, 

decks and topside modules. According to a survey of 51 yards, nine have single piece

fabrication capacity of more than 10,000 short tons and 12 indicate a capability to fabricate 

structures intended for water depths exceeding 1,000 ft (Hunt and Gary 2000).

As the drilling industry ventures further offshore in search of new fields, the fabrication yards are 

being challenged by the need for new technologies. Fabrication yards are affected directly by 

the trends and developments of the offshore industry, and as it grows and expands, so must the 

fabrication yards. “The [deepwater] trend has brought to the fabrication yard a multitude of new 

systems and challenges requiring risk, skill, size and ingenuity. ... For many fabrication yards, 

these new technologies and floating structures represent a more precise, higher risk, and

significantly larger project than they have had in the past, with a complexity requiring added 

involvement from engineering firms, vendors and component specialists” (Hunt and Gary 2000).

Supply Bases: Supply bases can range from large yards, offering all kinds of service including 

full logistics management, to smaller shops that supply one or many of the items needed on an 

offshore platform or marine vessel. From strategic locations along the Gulf, larger supply 

companies who offer supply chain management services move equipment and supplies from 

land-based supply houses to offshore drilling platforms. Other, smaller suppliers act more or 

less like a retail store, supplying anything from crane rentals, warehouse space, trailer rentals, 

and dispatch services, to engine parts, fuel, navigation tools, potable water, and lubricants 

including, motor oil, hydraulic oil, natural gas compressor oils, grease, gear oil, and synthetics. 

Based on an inventory conducted as part of the development of a GIS database for this project, 

95 supply base facilities that support the oil and gas industry were recorded within the Gulf 

region; 53 are located in Louisiana, 32 in Texas, 7 in Alabama, and 3 in Mississippi.

Crew Services: A number of companies provide services to the crews that live on the offshore 

rigs. These companies provide catering – delivering and serving hot meals – and laundry, 

cleaning, and maintenance services for crew barracks.
29

Based on an 2001 inventory conducted as part of the development of a GIS database for this 

project, 253 crew base facilities that support the oil and gas industry were recorded within the 

Gulf region; 125 are located in Texas, 83 in Louisiana, 2 in Florida, 6 in Mississippi, and 4 in 

Alabama.

3.3 Industry Characteristics

Rapidly developing technology has resulted in changing needs. This, in turn, has placed a 

burden on ports to provide the necessary infrastructure and support facilities in a timely manner 

to meet growing industry needs. This results in several important trends for ports (American 

Association of Port Authorities 2002b): 

1. the volume of trade and cargo moving through ports is increasing;

2. vessel sizes are increasing and require deeper channels;

3. ports, as with other industries, need to maintain environmental and economic

balance in their operations; and,

4. all of these trends create a greater need for capital investment in port infrastructure.

Increased Volume: Deep-draft ports accommodate ocean-going vessels which move over 95 

percent of U.S. overseas trade by weight and 75 percent by value. Since the enactment of the 

North American Free Trade Agreement in 1993, U.S. waterborne exports to Mexico and Canada 

have increased by more than 60 percent. And, according to U.S. Customs, the volume of 

imported cargo moving through U.S. ports is projected to more than double by the year 2020

(American Association of Port Authorities 2002b). 

According to a 1999 report to Congress assessing the Maritime Transportation System, “the 

demand for commercial use of the marine transportation system continues to grow, fueled by 

increases in world trade and domestic use of the waterways to transport goods and people.... 

Accordingly, there is a critical need to improve productivity, throughput capacity, mobility, and 

accessibility to meet the projected growth in world trade...” (Maritime Administration 1999).

As this waterborne trade continues to grow, so will the need for more efficient and effective 

cargo movement throughout the port system. The entire maritime system relies on the

successful integration of freight modes – water, truck and rail – for the smooth transit of cargo 

and passengers from vessels through terminals and to and from inland destinations. Without 

efficient access, port and terminal investments cannot be fully realized or used (Maritime 

Administration 2002a). According to a survey by MARAD (published August 2002) the current 

state of the intermodal access system for U.S. ports is generally acceptable for handling the 

existing volume of cargo flows. However, “acceptable” is different than “optimal” and if the 

cargo flow is expected to increase, more attention will need to be focused on the intermodal 

system. Of the 59 ports responding to the MARAD survey, “[m]any indicated that intermodal 

access conditions were at or above acceptable levels to handle current cargo flows, reflecting 

the significant investments that have been made in the last several years by federal, state and 

local governments in the marine transportation system. However, a large portion of the ports 

still indicated that flow conditions remain unacceptable and, therefore, require additional

attention. ... Twenty-five percent of the ports indicated that the local roads used to access their 

facilities had unacceptable flow conditions. More than one-quarter of the ports indicated that 
30

channel depths were still unacceptable in federal waterway channels” (Maritime Administration 

2002a). 

Larger Ships/Deeper Channels: As cargo volumes increase, carriers look for ways to cut time 

and costs, and so the number and size of vessels are growing. Vessels that began service in 

the 1960s with capacities of less than 500 twenty-foot equivalent units (TEUs) have been 

replaced by vessels with capacities of 6,000 TEUs, and carriers planning for increased cargo 

volume have ordered ships that can carry over 8,000 TEUs.5 By 2010, ships carrying 13,000 

TEUs are possible (NOAA 2002). These enormous ships require sophisticated and efficient 

ports and terminal facilities with first-rate landside intermodal connections. “For a port to service 

these mega ships, the entire port structure will have to get bigger and more productive. Each 

channel, berth, and turning basin must be at least 50 feet in depth since 40 to 46 feet will be the 

maximum draft for the fully-loaded mega ships” (Maritime Administration 1998).

In addition to building ships, ocean carriers are merging, forming alliances and establishing 

partnerships to strengthen their bargaining power and profitability. These new vessels serve 

high volumes and long distances, with many operating as part of vessel sharing agreements or 

alliances. “In 1996, the top-20 lines operators owned some 54 percent of the total container 

ship fleet capacity and over half of these operators have now formed three large alliances”(van 

der Veer 2001).

As a result of the greater volumes of cargo, larger ships and larger companies, ports are under 

pressure to increase their scale as well. The major consideration for ports when planning for 

larger ships is channel depth. Channel depths at most U.S. ports typically range from 35 to 45 

feet. The current generation new large ships require channels from 45 to 53 feet. Container 

ports around the world are deepening navigation channels down to between 49 and 53 feet.

Economy v. Environment: It is clear that the volume of trade done through ports is booming 

and there is a critical need to improve productivity, throughput capacity, and accessibility. 

However, this comes with a cost, or rather a trade off – environmental quality of the coastal 

landscape and its surrounding waters versus economic growth. “One of the critical challenges 

confronting the U.S. port industry is meeting the growing demands and diverse needs of 

waterborne transportation while protecting the environmentally sensitive harbor areas in which 

ports operate. Protecting the environment and providing an efficient and cost-effective 

transportation system are critical to the economic future of the United States” (Maritime

Administration 1998). In American Association of Port Authorities (AAPA) member surveys 

conducted in 1993 and 1999, the top strategic issues for U.S., Canadian, Caribbean, and Latin 

American ports were facility expansion and the ports’ ability to secure funding, followed by 

pricing pressures and meeting environmental requirements.

Ports and terminal operations pose environmental risks that conflict with habitat conservation 

objectives in the U.S.’s already congested waterways. Some of the potential impacts upon

environmental quality that can result from many port operations and related activities include:

Port Development and Watershed Impacts: Port expansion, bulkhead installation, land filling, 

pier construction/ rehabilitation, dredging, and dredged material placement are among the port 

 

5

It’s possible for a shipping company to save $4.5 million per voyage by switching from a 2,500 to 

6,000 TEU vessel.
31

activities that directly affect water quality, including wetland and other habitat loss, degradation, 

and creation. U.S. coastal areas — including both the waterfront and the waterways — support 

an extensive and unique set of ecological, commercial, and recreational functions, and provide 

food, shelter, and nursery areas for birds, marine invertebrates, fish, and other wildlife. Many of 

these productive areas have been modified or lost to support residential, agricultural, industrial, 

and commercial growth, as well as expansions of ports and terminals. 

In Louisiana, Port Fourchon is one of the primary port facilities that services oil and gas 

exploration and production. “What is of particular importance is that the facility and the highway 

system that connects it to the interstate highway system are protected by only the surrounding 

landscape, which happens to be coastal marshes. Without this critical landscape that functions 

as a ‘marsh barrier,’ the highway system would be threatened by winter storms, high tides, 

tropical storms, and hurricanes” (Battelle 2002). If the highway were to be damaged, so would 

the flow of natural gas and crude oil production and delivery. Another valuable and protective 

function provided by this landscape is the levees and miles of coastal wetlands in front of them 

that protect thousands of residents and businesses from floods, storms and waves. If this 

essential marsh barrier were removed, the existing levees would have to be enlarged and 

armored significantly. 

In addition to the protective landscape, this coastal landscape also supports Louisiana’s multibillion dollar fishing industry. A healthy ecosystem depends on a habitat that will support the 

many estuarine species that are a part of the ecological web in the Gulf of Mexico. Without this 

landscape, Gulf fisheries and wildlife such as waterfowl, alligators and neotropical migrants 

would be detrimentally affected. Because of natural processes and lingering effects of past

activities and destruction, the coastal landscape is being converted to open water at the rate of 

30 to 35 square miles per year (Battelle 2002). 

Vessel-Support Activities: Vessel maintenance and construction activities also pose

environmental risks. In fact, it is one of the water transportation sector’s greatest environmental 

concerns. The major waste streams are chemical paint stripping, abrasive blast and surface 

preparation, painting and painting equipment cleaning, solvent, and engine overhauling and 

repair. In addition to particulate emissions, ship maintenance and repair activities emit various 

chemicals such as volatile organic compounds into the air.

Painting a vessel to improve appearance and performance and to prevent corrosion and hull 

fouling is an important maintenance practice. Prior to applying new paint however, the surface 

must be stripped and the old paint removed. This is usually done with a chemical paint stripper 

based on methylene chloride or with abrasive blasting. Blasting is used primarily because the 

medium is not hazardous – like garnet, flint grit or steel shot (Office of Compliance 1997a).

Engine repairs and other types of vessel repairs are also performed at the port facilities. 

Repairs may vary from small automotive-type engines to large boilers and turbines of tankers 

and other cargo vessels. These repairs result in waste such as spent lubricants and engine oils, 

solvents, batteries and coolants. Other repairs may include sheet metal work, metal finishing, or 

other specialty operations. Table 3.4 displays typical materials used in this repair and 

maintenance sector and their resulting wastes. 
32

Table 3.4

Vessel Maintenance Operations, Typical Raw Material Inputs, and Pollution Outputs

Operation Raw Material Input Pollution Output

Paint Removal Chemical paint stripper, blast 

media

Wastewater containing blasting 

media, organic paint sludges, heavy 

metals, stripping chemicals, volatile 

organic carbons (VOCs)

Painting Antifouling paints Waste paints, thinners, degreasers, 

solvents, resins and gelcoat, VOCs

Engine Repair Degreasing solvents, carburetor 

cleaner

Waste turbine oil, lubricants, 

degreasers, mild acids, batteries, 

carburetor cleaners, VOCs

Machine Shop Solvents, cutting fluids, 

degreasing acids and alkalies

Spent cutting and lube oils, scrap 

metal, degreasers, VOCs

Metal Finishing Cyanide, heavy metal baths, 

acids and alkalies

Cyanide solutions, heavy metal 

sludges, corrosive acid, and alkali 

solutions

Source: Office of Compliance (1997a) 

Because most shipbuilding and repair takes place outdoors, over, in and around water – it 

exposes the marine waters to these potential pollutants. Repair and maintenance yards

represent the most prevalent pollution risk in the industry. Also, by their very nature of being 

able to hold water, large impervious surface areas, and their location, many of the activities at 

marine facilities are exposed to nature’s elements and, therefore, are also large generators of

stormwater. Stormwater frequently carries sediments, chemicals and debris from the ground

surface, as it runs off into the marine or river waters. 

Many municipalities and some industries are incorporating wetlands into their wastewater

treatment systems to remove nutrients, process some chemical and organic wastes, and reduce 

sediment loads prior to discharge into riverine and marine waters. This form of pretreatment 

reduces industry and municipality costs, protects shellfish and swimming areas from closures, 

and reduces the number of fish consumption advisories issued.

Cargo Handling/Landside Vehicle Emissions: Although most environmental hazards in a marine 

facility result from the repair and maintenance services provided to vessels, there are also 

problems that occur as a result of cargo handling. “A significant amount of diesel-powered 

equipment is used in a typical marine facility, such as forklifts, tractors, and front-end loaders. 

Air emissions from these vehicles, when combined with those from vessels, as well as from 

trucks and trains that deliver and remove cargo, may contribute to nonattainment of certain air 

requirements” (Office of Compliance 1997a). 

The operations that handle bulk cargo use advanced equipment such as pneumatic continuous 

ship loaders and unloaders, conveyer belts, stockpiling and reclaiming machines or cranes with 

grab buckets and front-end loaders. As the industry expands, so will the need to unload cargo 

quicker and faster. These loading and unloading techniques produce high amounts of dust and 
33

solid waste accumulation. Dry bulk-transfer operations generally have dust control problems 

because dust is generated each time cargo is transferred. Liquid bulk-transfer operations can 

be a source of hydrocarbon emissions that are readily converted into photochemical smog by 

radiation from the sun (Office of Compliance 1997a).

Dredging: Proper depth in navigation channels allows ships to move safely through harbors and 

provides turning basins and adequate water depth alongside terminal facilities. To maintain this 

depth, several hundred million cubic yards of sand, gravel and silt must be dredged from 

waterways and harbors each year. However, this maintenance and improvement process is 

challenging and controversial because ports are located in or near some of the Nation’s most 

environmentally sensitive areas – valuable wetlands, estuaries and fisheries. And, the materials 

that are dredged may uncover toxins or contaminated sediments that have accumulated over 

time.6

Legal and Regulatory Framework: Under the Clean Water Act (Section 404), the U.S. Army 

Corps of Engineers (USACE) manages the program that directs dredging and disposal of

dredged material from navigation improvement and maintenance programs. The USACE is 

responsible for developing and maintaining Federal navigation channels. In addition, nonFederal permit applicants (e.g., port authorities, pipeline operators, terminal owners, industries, 

and private individuals) dredge another 100 million cubic yards annually. The USACE reviews 

potential projects and issues permits for dredging and disposal of the dredged material in 

accordance with Federal regulations.

The EPA oversees and develops the environmental criteria by which the USACE evaluates 

proposed disposal of dredged material. The EPA also designates and monitors ocean-dredged 

material disposal sites. A USACE permit is required when dredged sediments are disposed of 

in the ocean, inland, or near-coastal waters. If dredged material is disposed of on land, various 

Federal, State, and local regulations may apply.

The legal and regulatory framework regarding dredging consists of a number of statutes and 

regulations that are based upon a variety of different goals and objectives. For this reason

dredging projects can become stalled in the review process. The problems that can hinder the 

dredging process fall into the following categories: planning; project review; scientific

uncertainties; inconsistent funding allocations; and inconsistent vertical and horizontal

collaboration among governmental offices and stakeholders. In 1995, the National Dredging 

Team was established to facilitate communication, coordination, and resolution of dredging 

issues among Federal agencies and to ensure that dredging of U.S. harbors and channels is 

conducted in a timely, environmentally sensitive, and cost-effective manner. Regional Dredging 

Teams have also been formed around the country to provide forums for local and regional issue 

resolution; foster the exchange of information with stakeholders; and provide liaison with local 

planning groups. 

Reducing Contaminated Materials: The complexities of the physical, chemical, and biological 

composition of the sediment and the environmental conditions specific to each disposal site 

create uncertainties in scientific evaluations and testing of dredged materials. This increases 

 

6

 Unless otherwise noted, the remainder of the discussion on dredging is derived from: Maritime 

Administration, A Report to Congress on the Status of the Public Ports of the United States 1996 - 1997, 

(Washington D.C.: Department of Transportation).
34

the need to develop scientifically dependable toxicity tests and a biological-effects database for 

contaminants that bioaccumulate. It is important to improve the understanding of the science 

involved in dredged material management because this information assists risk managers in 

making scientifically sound decisions that protect ecological resources and human health.

Although contaminated sediments pose a complex problem, so does the volume of sediment 

entering the waterway. Progress has been made in decreasing the contaminants that get 

discharged into waterways; however, stormwater runoff remains a major concern. Management 

practices (soil erosion control, reduced use of fertilizers, chemicals, etc.) and planned growth 

could be used to reduce pollution entering the waterway. Approaches that may help are:

planning development to maintain buffers along the waterways, minimizing the burden on 

municipal sewer systems, and controlling runoff from paved surfaces. These efforts, combined 

with attempts to decrease contaminant discharge and the removal of existing contaminated 

sediments through dredging, should result in some reduction in the future amount of dredged 

material that is contaminated. 

Reuse of Dredged Material: Although the dredging and resurfacing of contaminated sediments 

is a major topic, really, only “5 to 10 percent of dredged material is contaminated and some of 

this material may, in some cases, also be reused in beneficial applications” (Maritime

Administration 1999). In recent years there has been a change in emphasis on dredged 

material management to maximize its potential use – dredged material can also be a resource 

to be used beneficially. Among the beneficial uses for dredged materials are beach

nourishment, wetlands creation, habitat restoration, barrier island reclamation, manufactured 

soil, abandoned mine reclamation, contaminated site remediation, and landfill for development 

and recreation uses (Maritime Administration 1999).

“Ports will continue to explore beneficial uses of dredged material — options such as using the 

material as top soil, potting soil, aggregates, or even bricks. Options other than ocean disposal, 

however, inevitably increases project costs and requires longer lead times for planning dredging 

projects. Planning such projects is part of the role ports play to balance economic reality with 

environmental requirements” (American Association of Port Authorities 2002b).

Dredging Expenditures: Capital expenditures on dredging were 11.1 percent of total port 

expenditures in the U.S. for 2000. The Gulf Coast Region accounted for 29 percent of these 

expenditures, exceeded only by the North Atlantic Region at 34 percent. The Gulf Coast

Region was followed by the South Pacific region with 27 percent, the North Pacific region with 6 

percent, and South Atlantic with 4 percent. Dredging in the Great Lakes accounted for less than 

0.1 percent of total dredging expenditures (Maritime Administration 2001a).

Investment in Infrastructure: As previously discussed throughout this report, improving and 

maintaining navigation channels is critical to sustaining the rapidly growing marine transport 

industry. Bottlenecks can occur when channels are not deep enough for ships to safely 

navigate and dock at berths. Unless ports are dredged, cargo cannot move in the most costeffective way through the intermodal transportation chain. Also, as ship sizes and volumes of 

cargo increase, so must the intermodal transfer operations. 

Efficient transportation depends on intermodal connections. In order to move waterborne cargo 

quickly to or from land based operations, trucks and railroads need to have clear access to

ports. “For some ports, the weakest link in their logistics chain is at their back doors, where 
35

congested roadways or inadequate rail connections to marine terminals cause delays and raise 

transportation costs” (American Association of Port Authorities 2002 c). According to the AAPA, 

a 2000 Federal Highway Administration Report to Congress on the National Highway System 

(NHS) Intermodal Connectors cited that connectors to ports, as opposed to other freight

terminals, were found to be in the worst condition and received the smallest level of funding. 

They also had twice as many miles with pavement deficiencies when compared to nonInterstate NHS routes. Like a pipeline, the nation’s intermodal transportation system is only as 

efficient as its narrowest, most congested point – often, the landside connection. No matter how 

much ports invest or how productive their marine terminal facilities, the transportation system 

cannot operate to maximum efficiency unless cargo can move quickly, and cost-effectively, in or 

out of ports.

The importance of major intermodal marine linkages or connections to surface transportation 

was recognized in the National Highway System Designation Act of 1995. The Act listed

directions for modifications to connections to major ports, airports, international border

crossings, public transportation and transit facilities, interstate bus terminals, and rail and other 

intermodal transportation facilities. In 1998, the Transportation Equity Act for the 21st Century 

(TEA-21) was signed, authorizing highway, highway safety, transit and other subsurface

transportation programs for the next 6 years. Within TEA-21, there are a number of programs 

that could potentially benefit port industry access concerns. Although these programs do not 

earmark specific funds for port related projects, they may meet program eligibility requirements.7

Financing Improvements: To keep up with changing vessel sizes and industry trends, ports 

must continuously update, modernize, and expand their facilities. Since 1946, U.S. ports have 

invested $21.9 billion in capital improvements and related infrastructure. During this period, the 

Gulf Coast region accounted for over 18 percent of these expenditures, only to be exceeded by 

the South Pacific region (30 percent). From 1996 through 2000, the public port industry 

invested over $6 billion in capital improvements. Approximately 16.5 percent of this 5-year 

spending was in the Gulf Coast region. The Gulf region’s spending was exceeded by South 

Pacific region at 39 percent and the South Atlantic region at 17 percent. 

During the five-year period of 2001-2005, public port expenditures are predicted to reach a 

record total of $9.4 billion – an increase of 12.8 percent compared to last year. The South 

Pacific region continues as the focus of future investment activity with proposed expenditures of 

$3.1 billion (33.8 percent). Four other regions are projecting investment levels in excess of $1 

billion – the South Atlantic at $1.7 billion (18.8 percent), the Gulf at $1.6 billion (17.1 percent), 

the North Atlantic at $1.5 billion (16.6 percent), and the North Pacific at 1.2 billion (12.8 

percent). From a coastwise perspective, the West Coast is projecting to invest over $4.3 billion,

with East Coast expenditures at $3.3 billion and the Gulf at $1.6 billion (Maritime Administration 

2001).

3.4 Regulations

Public ports are usually established by state and local governments to develop, manage and 

promote the flow of waterborne commerce in the area. Ports can also be developed by private 

companies. A port authority – which can be a state or local government, private agency or firm 

 

7

 This discussion was derived from: Maritime Administration, A Report to Congress on the Status of 

the Public Ports of the United States 1996 - 1997, (Washington D.C.: Department of Transportation).
36

– is the governing body that oversees the ports operations. In addition to maritime functions, 

port authority activities may also include jurisdiction over airports, bridges, tunnels, commuter 

rail systems, inland river or shallow draft barge terminals, industrial parks, Foreign Trade Zones, 

world trade centers, terminal or shortline railroads, ship repair, shipyards, dredging, marinas and 

other public recreational facilities.

The port authority is governed by a commission with members that are appointed by city and 

county governments. For instance, the seven-member Port of Houston Commission is the 

governing body for the Port of Houston Authority. The City of Houston and the Harris County 

Commissioners Court each appoint two commissioners. These two governmental entities jointly 

appoint the chairman of the Port Commission. The Harris County Mayors and Councils

Association and the City of Pasadena each appoint one commissioner.

In addition to the Commission, the port authority may have an executive office. The staff is 

responsible for overseeing the day-to-day operations of the port and implementing policies and 

directives given by the Port Commission. They also supervise other divisions of the authority 

such as: Administration, Facilities, Operations, Trade Development, Protection Services and 

Public Affairs.

Legislation: The Ports and Waterways Safety Act (PWSA)8 is designed to promote navigation, 

vessel safety, and protection of the marine environment. The PWSA applies in any port or 

place under the jurisdiction of the U.S. Waters subject to the jurisdiction of the U.S. are defined 

as navigable waters, other waters on lands owned by the U.S., and waters within U.S. territories 

and possessions of the U.S. 

The PWSA requires the U.S. Coast Guard to promulgate regulations regarding “design, 

construction, alteration, repair, maintenance, operation, equipping, personnel qualifications and 

manning of vessels... necessary for the increased protection against hazards to life and

property, for navigation and vessel safety and for enhanced protection of the marine

environment.”9 The Act also authorizes the U.S. Coast Guard to establish vessel traffic

service/separation (VTSS) schemes for ports, harbors, and other waters subject to congested 

vessel traffic. These schemes help provide order and predictability to vessel movements by 

establishing lanes with a “separation zone” between opposing vessel traffic similar to the 

“median” between opposing traffic on the highway system. VTSS apply to commercial ships, 

other than fishing vessels, weighing 300 gross tons or more.

The PWSA was amended by the Port and Tanker Safety Act of 1978 (PTSA). Under this 

amendment, Congress found that navigation and vessel safety and protection of the marine 

environment are matters of major national importance and that increased vessel traffic in the 

nation's ports and waterways creates substantial hazard to life, property or the marine

environment. Also, increased supervision of vessel and port operations was found necessary in 

order to: 

1. reduce the possibility of vessel or cargo loss, or damage to life, property, or the 

marine environment; 

 

8

 The PWSA was amended by the Port and Tanker Safety Act of 1978 (PTSA), Public Law 95-474, 

and the Oil Pollution Act of 1990 (OPA). 

9

 46 USC 3703(a)
37

2. prevent damage to structures in, on, or immediately adjacent to the navigable 

waters of the U.S. or the resources within such waters; 

3. ensure that vessels operating in the navigable waters of the U.S. shall comply with 

all applicable standards and requirements for vessel construction, equipment,

manning, and operational procedures; and 

4. ensure that the handling of dangerous articles and substances on the structures in, 

on or immediately adjacent to the navigable waters of the U.S. is conducted in 

accordance with established standards and requirements.10

Under the PTSA, it was also determined that advanced planning is critical in determining proper 

and adequate protective measures for the nation's ports and waterways and the marine

environment, with continuing consultation with other federal agencies, state representatives, 

affected users and the general public, in the development and implementation of such 

measures.

“The PTSA provided broader regulatory authority over regulated and non-regulated areas. It 

provided for improvements in the supervision and control of all types of vessels operating in 

navigable waters of the U.S., and in the safety of foreign or domestic tank vessels that transport 

or transfer oil or hazardous cargoes in ports or places subject to U.S. jurisdiction” (NOAA 2002).

3.5 Industry Trends and Outlook

The offshore drilling industry has come a long way since it installed the first subsea wellhead in 

1964. The Gulf of Mexico represents an expanding frontier with extraordinary growth –

especially of deepwater oil and gas industry activity over the past 7 years. And, the point of 

discussing the growth of the offshore industry in the Gulf Mexico is that, as it grows, so does the 

need for support services provided by regional ports. As previously stated, regardless of where 

the exploration and production equipment, personnel and supplies originate, at some point

these resources must pass through a port to reach the drilling site. This point of intermodal 

transfer is vital to maintaining reliable, uninterrupted production of oil and gas from the Gulf.

According to a recently released MMS report, “[t]he large volume of active deepwater leases, 

the increased drilling program, and the growing deepwater infrastructure all indicate that the 

deepwater GOM will increase in importance as an integral part of this nation's energy supply 

and will remain one of the world's premier oil and gas basins” (USDOI, MMS 2002a). According 

to the MMS report, 59 percent of all oil production in the Gulf comes from deep water. And even 

in the short time since the MMS’s last report in 2000 (USDOI, MMS 2002a), several

“remarkable” achievements have been made, for example:

• The number of drilling rigs working in deepwater has increased from 28 to 43; 

• The number of ultra-deepwater (> 5,000 ft) capable rigs has increased from 18 to 26 

(44 percent) and the number of ultra-deepwater wells increased from 37 to 59 (59

percent);

• There was a 59 percent increase in the number of producing deepwater fields;

 

10 33 USC 1221
38

• Deepwater oil production is rapidly approaching the all-time shallow-water oil

production record established in 1971.

• New deepwater drilling added over 4 billion BOE, a 49 percent increase, to the Gulf 

of Mexico oil and gas inventory.

New advances in technology are also stimulating investment in the Gulf, although the oil majors 

remain a leading force on the shelf, the independents are starting to gain more acreage (Energy 

Day 2002). In March 2002, independent producers accounted for 70 percent of the $363.2 

million bid on blocks offered in the Central Gulf of Mexico Lease Sale 182. Although Phillips 

Petroleum had the highest bid – $17.5 million for deepwater block 199 in Green Canyon – it was 

the independents that “really spread the cash around.” For instance, Dominion Exploration & 

Production spent $37 million for 37 tracts and Spinnaker Exploration spent $28.8 million for 42 

tracts. The two companies also teamed up to win about $20 million worth of other high-profile 

tracts (Gas Daily 2002a).

Another lease sale, in August 2002 – Western Gulf Lease Sale 184 – provided more

opportunities for companies to gain acreage. As will the 11 additional block sales (shown in 

Table 3.5) as proposed by the MMS in their “Proposed Final Outer Continental Shelf Oil & Gas 

Leasing Program, 2002-2007.” 

Table 3.5

 Gulf of Mexico Lease Sale Schedule – Proposed for 2002-2007.

Sale No. Area Year

184 Western Gulf of Mexico 2002

185 Central Gulf of Mexico 2003

187 Western Gulf of Mexico 2003

189 Eastern Gulf of Mexico 2003

190 Central Gulf of Mexico 2004

192 Western Gulf of Mexico 2004

194 Central Gulf of Mexico 2005

196 Western Gulf of Mexico 2005

197 Eastern Gulf of Mexico 2005

198 Central Gulf of Mexico 2006

200 Western Gulf of Mexico 2006

201 Central Gulf of Mexico 2007

Source: USDOI, MMS (2002b) 

Inventory:

Table 3.6 provides results of a 2001 inventory of the major port facilities in the Gulf which 

provide support services such as those described in previous sections of this chapter to the 

offshore oil and gas industry. 
39

Additional information regarding individual ports can be found in Appendix II.

With increased development comes a need for additional support and port expansion. For 

example, this need has already been experienced in Manatee County, Florida with the

expansion of Port Manatee and its windfall from the Gulfstream Pipeline Project.

Port Manatee: Port Manatee in Manatee County, Florida is in the middle of a considerable 

expansion effort with more than $60 million of projects under design or construction. It is hoped 

Table 3.6

Major Port Facilities Servicing the Offshore Oil and Gas Industry in the Gulf

 Name Operator City State

 Port of Mobile/Alabama State Docs Alabama State Port Authority Mobile AL

 Port of Manatee Manatee County Port Authority Palmetto FL

Port of Panama City Panama City Port Authority Panama City FL

Port of Pensacola Pensacola Port Authority Pensacola FL

Port St. Petersburg Port St. Petersburg St. Petersburg FL

Port of Tampa Tampa Port Authority Tampa FL

 Port of Greater Baton Rouge Greater Baton Rouge 

 Port Commission Port Allen LA

Port of Fourchon Greater Lafourche Port Commission Port Fourchon LA

Port of Grand Isle Grand Isle Port Commission Grand Isle LA

Port of Iberia Port of Iberia New Iberia LA

Port of Lake Charles Port of Lake Charles Lake Charles LA

Port of New Orleans Port of New Orleans New Orleans LA

 Port of Plaquemines Plaquemines Parish Port,

Harbor and Terminal District Braithwaite LA

Port of South Louisiana Port of South Louisiana LaPlace LA

St. Bernard Port St. Bernard Port Chalmette LA

 Port of Pascagoula Port of Pascagoula Pascagoula MS

 Biloxi Port Biloxi Port Biloxi MS

Port of Gulfport Port of Gulfport Gulfport MS

 Port of Beaumont Port of Beaumont Beaumont TX

Port of Brownsville Port of Brownsville Brownsville TX

Port of Corpus Christi Port of Corpus Christi Corpus Christi TX

Port of Freeport Port of Freeport Freeport TX

Port of Galveston Port of Galveston Galveston TX

Port of Houston Port of Houston Authority Houston TX

Port of Orange Orange County Navigation and Port Orange TX

Port of Port Lavaca-Point Comfort Calhoun County Navigation District Point Comfort TX

Port of Port Arthur Port of Port Arthur Port Arthur TX

Port of Texas City

 Texas City/Terminal Port of Texas City Texas City TX

Port of Victoria Victoria County Navigation District Victoria TX

 

Source: The Louis Berger Group, Inc., 2001 
40

that the Port expansion will encourage investments and contracts from industries such as 

perishable commodities, cruise operations and containerized cargo. 

Three berths are under construction or expansion. Berth 12 is 1,450 feet long and when

complete will have a depth of 40 feet on a 400 foot wide channel. A utilitarian berth for 

providing service for cruise, general and containerized cargo will also be built. Berth 5 is being 

constructed for Vulcan/ICA. The 800 foot long berth will be home to Vulcan’s 700 foot self

discharging bulk ships. The berth should be completed by December 2003. Additionally, a new 

60,000 square foot cold storage warehouse is being added to Port Manatee’s Berth 11. 

Theodore, AL: Bredero Price Co. has recently opened a 500-employee facility in Theodore, 

Alabama to coat piping for deepwater oil and natural gas applications. The project, initially 

costing approximately $45 million, was expanded beginning in late 2001, with an investment of 

at least $20 million. The Houston-based company is expected to install a new pipe welding 

area, pipe-coating line addition, and several batch concrete plants. Additionally, new docking 

facilities were installed to accommodate product loading onto the largest ocean-going vessels

(Industrial Information Resources, Inc. 2001).

In addition to each of these major expansions is the economic windfall that has and will continue 

to result from the Gulfstream Natural Gas Project. 

Gulfstream Natural Gas Project: The Gulfstream Natural Gas Project is a 753-mile pipeline 

that originates near Pascagoula, Mississippi and Mobile, Alabama and crosses the Gulf of

Mexico (with 431 miles of 36-inch diameter pipe) to Manatee County, Florida. Onshore, 306 

miles of pipe, ranging in diameter from 36 inches to 16 inches, stretches across south and 

central Florida, terminating in Palm Beach County. Placed into service on May 28, 2002, the 

$1.6 billion pipeline project will provide approximately 1.1 bcf per day of natural gas to fuel new 

electric generation capacity throughout Florida. 

Gulfstream has precedent agreements with 10 large Florida utilities and power generation 

facilities which represent long-term commitments for the majority of its 1.1 bcf per day. 

Subsidiaries of Duke Energy and Williams purchased 100 percent interest in the Gulfstream 

Project from Coastal Corporation in February 2001.11 

The pipeline is expected to have added $10 million to $12 million to Port Manatee’s bank 

account during construction, which includes the $3 million that has already been realized. The 

Gulfstream project ordered 450,000 tons of steel pipe from Berg Steel Pipe Corp. of Panama 

City. The project required Berg to import about 40 percent of the pipe from its European parent 

company because of the time constraints of the project. The project created opportunities for 

two Port Manatee tenants, Eastern Cement Corporation and Lafarge Florida Inc., to sell

products used for the pipeline construction. In addition to using the port for import, export and 

storage, the Project has leased 190 acres of port property for pipeline staging and storage (The 

Business Journal 2002). The project also included Bredero Price Co. of Theodore, Alabama 

coating approximately 60 percent of the pipe with concrete for deepwater placement (Scott 

2002).

 

11 Due to regulatory mandates related to Coastal Corporation’s merger with El Paso Energy

Corporation, Coastal was forced by FERC to divest the project.
41

3.6 Summary

It is apparent that the oil and gas industry continues to thrive in the Gulf of Mexico. With the 

industry has come a logistical support system that links all phases of the operation and extends 

beyond the local community. Land-based supply and fabrication centers are providing the 

equipment, personnel and supplies necessary for the industry to function through intermodal 

connections at the Gulf Coast ports. The necessary onshore support segment includes inland 

transportation to supply bases, equipment manufacturing and fabrication. The offshore support 

involves both waterborne and airborne transportation modes. 

As the industry continues to evolve, so do the requirements of the onshore support network. 

With advancements in technology, the shore side supply network will continue to be challenged 

to meet the needs and requirements of the industry. All supplies must be transported from landbased facilities to marine vessels or helicopters to reach offshore destinations. This utilizes 

both water and air transportation modes. The intermodal nature of the entire operation gives 

ports (who traditionally have water, rail and highway access) a natural advantage as an ideal 

location for onshore activities and intermodal transfer points. Therefore, ports will continue to 

be a vital factor in the total process and must incorporate the needs of the offshore oil and gas 

industry into their planning and development efforts, particularly with regard to determining their 

future investment needs. In this manner, both technical and economic determinants must

influence the dynamics of port development.

This extensive network of supply ports includes a wide variety of shore side operations from 

intermodal transfer to manufacturing. Their distinguishing features show great variation in size, 

ownership and functional characteristics. Basically, two types of ports provide this supply base. 

Private ports operate as dedicated terminals to support the operation of an individual company. 

They often integrate both fabrication and offshore transport into their activities. Public ports 

lease space to individual business ventures and derive benefit through leases, fees charged 

and jobs created. These benefits spread throughout the entire area and are viewed as

economic development impacts. Thus, the public ports play a dual role by functioning as

offshore supply points and as industrial or economic development districts. An efficient network 

of ports lowers costs associated with oil and gas production and significantly boosts the well 

being of citizens of the adjacent communities.

Port profiles present information depicting the basic characteristics of a few sample oil and gas 

ports. These exemplify the type of infrastructure and operational parameters that are common 

to oil and gas support bases. Their institutional framework indicates the governing hierarchy 

ultimately responsible for the future direction of the port and its impacts on the local community. 

It is anticipated that these characteristics are consistent with the level of effort and development 

necessary to support offshore oil and gas industrial development. However, to continue to offer 

a viable service and to stay current with technological trends and industry standards, ports must 

be able to incorporate this information into their planning for future infrastructure development, 

staffing needs, and other impacts associated with rapid industrial growth.

Issues and concerns that must be addressed at the local level have resulted from the significant 

prosperity that has followed the industry. These extend beyond specific port needs into the 

community itself. For example, additional commercial traffic has caused worsening road

conditions. Additional population has generated housing problems and the need for more law 

enforcement. Greater demand for potable water has brought about shortages. The local
42

schools are stretched to their limits in accommodating more children. All of these problems can 

be nullified with additional infrastructure. However, additional infrastructure is difficult to

develop. It is expensive to construct and requires substantial planning and construction time 

prior to completion.

Even though local governments have gained revenue from the increased activity in their

jurisdictions, the demands for additional services and facilities resulting from oil and gas

operations have exceeded growth in the revenue stream. Local tax dollars cannot meet the 

demand for so many improvements in such a short time. State and federal matching funds are 

being sought where possible. But the acquisition of those funds often has built in delaying 

factors. Nevertheless, communities are attempting to meet the burgeoning demands of a

rapidly growing population base.

Thus, the industry is determining the direction and scope of improvements being made at local 

levels. Communities, just like the ports, must be able to anticipate future demands for their 

services. In order to plan for this growth, they need timely information about trends in the 

industry. The ability to identify and quantify offshore needs and growth directions is essential for 

the economic well being of the citizens and the continued ability, of both the ports and

communities, to provide the required offshore support.
43

4.0 SHIPYARDS/SHIPBUILDING

4.1 Introduction

The shipbuilding and repair industry builds ships, barges and other large vessels, whether selfpropelled or towed by other craft. Shipyards, or facilities that build ships, operate on a job basis. 

Unlike most other industries, each year only a small number of valuable orders are received that 

often take years to fill. Orders for ships and ship repairs are primarily placed by the federal 

government or companies that can include: commercial shipping companies, passenger and 

cruise companies, ferry companies, petrochemical companies, commercial fishing companies, 

and towing and tugboat companies. The principal federal government agencies placing 

shipbuilding and repair orders include the Naval Sea Systems Command, the Military Sealift 

Command, the Army Corps of Engineers, the U.S. Coast Guard, the National Oceanic and 

Atmospheric Administration (NOAA), the National Science Foundation, and the Maritime

Administration (Office of Compliance 1997b).

4.2 Description and Typical Facilities

Shipyards are often categorized into a few basic subdivisions either by type of operations 

(shipbuilding or ship repairing), by type of ship (commercial or military), and shipbuilding or 

repairing capacity (first-tier or second-tier). Ships themselves are often classified by their basic 

dimensions, weight (displacement), load-carrying capacity (deadweight), or their intended

service. In the U.S., there are considerable differences between shipyard operations when 

constructing ships for commercial purposes and when constructing ships for the military.12

Commercial Ships: Commercial ships can be subdivided into a number of classes based on 

their intended use. Commercial ship classes include dry cargo ships, tankers, bulk carriers, 

passenger ships, fishing vessels, industrial vessels, and others. Dry cargo ships include break 

bulk, container, and roll-on/rolloff types. 

Unlike the military market, the commercial ship market must also compete internationally, 

making it much more cost competitive. The cost of building and maintaining a ship must be low 

enough to allow owners to profit. This has a significant impact on the manner in which

commercial ships are built and repaired. The intense global competition in this industry is the 

main reason that since World War II, U.S. shipyards have produced relatively few commercial 

ships. In this regard, since 1981 the U.S. shipyards received less than one percent of all

commercial orders for large ocean going vessels in the world, and no commercial orders for 

large ocean going cruise ships. 

Military Ships: Military ship orders have been the mainstay of the industry for many years. 

The military ship market differs from the commercial market in that the major market drivers are 

agency budgets as set by government policy. The military ship market can be divided into 

combatant ships and ships that are ordered by the government, but are built and maintained to 

commercial standards rather than military standards. Combatant ships are primarily ordered by 

the U.S. Navy and include surface combatants, submarines, aircraft carriers, and auxiliaries. 

 

12 Unless otherwise noted, this discussion and remaining descriptions are taken from: Office of

Compliance, Profile of the Shipbuilding and Repair Industry (Washington D.C.: Office of Enforcement and 

Compliance Assurance, Environmental Protection Agency), 1997b, p. 3-4.
44

Government owned noncombatant ships are mainly purchased by the Maritime Administration’s 

National Defense Reserve Fleet (NDRF) and the Navy’s Military Sealift Command (MSC). Other 

government agencies that purchase non-combatant ships are the Army Corps of Engineers, 

National Oceanic and Atmospheric Administration, and the National Science Foundation. Such 

ships often include cargo ships, transport ships, roll on/roll off ships, crane ships, tankers, patrol 

ships, and ice breakers.

First and Second-Tier Shipyards: U.S. shipyards are also classified by the Maritime

Administration (MARAD) as either first-tier shipyards or second-tier shipyards. First-tier 

shipyards make up the “U.S. major shipbuilding base” (MSB). As defined by MARAD and the 

Department of Transportation in Report on Survey of U.S. Shipbuilding and Repair Facilities, 

2001 the MSB is comprised of privately owned shipyards that are open and have the capability 

to construct, drydock, and/or topside repair vessels with a minimum length overall of 122 

meters, provided that water depth in the channel to the facility is at least 3.7 meters. Facilities 

are further classified as (Office of Shipbuilding and Marine Technology 2001):

• Active Shipbuilding Yards: The Active Shipbuilding Yards are comprised of those 

privately owned U.S. shipyards/facilities, that are open, with at least one building 

position capable of accommodating a vessel 122 meters (400 feet) in length and 

over, and are currently engaged in the construction of naval ships and/or major 

oceangoing merchant vessels 122 meters (400 feet) in length and over.

• Shipyards with Build Positions: Privately owned shipyards/facilities that are open, 

with at least one build position capable of accommodating a vessel 122 meters in 

length and over, and that have not constructed a naval ship or major oceangoing 

merchant vessel in the past two years.

• Repair (with Drydocking): Shipyards that have graving docks, floating drydocks or 

marine rails capable of handling naval ships and/or major oceangoing merchant

vessels 122 meters in length and over.

• Topside Repair: Shipyards that have sufficient berth/pier space, including dolphins, 

to accommodate a naval ship or major oceangoing merchant vessel of 122 meters in 

length or over.

Second-tier shipyards are comprised of the many small and medium-size shipyards that

construct and repair smaller vessels (under 122 meters) such as military and non-military patrol 

boats, fire and rescue vessels, casino boats, water taxis, tug and towboats, off-shore crew and 

supply boats, ferries, fishing boats, and shallow draft barges. A number of second-tier 

shipyards are also able to make topside repairs to ships over 122 meters in length. These 

facilities are also further classified (Office of Shipbuilding and Marine Technology 2001): 

• Boatbuilding and Repair Companies: Privately owned shipyards capable of 

building and/or repairing commercial and military vessels less than 122 meters (400 

feet) in length.

• Vessel Repair Companies: Facilities that only provide repair services, either repair

with drydocking or topside repair, to vessels less than 122 meters (400 feet). These 

companies must have their own waterfront facilities.
45

• Fabricators/Manufacturers of Maritime Vessels: Companies that build small

commercial crafts less than 76 meters (250 feet).

4.3 Industry Characteristics

The Maritime Administration (1999) reported that there are approximately 93 private shipyards 

in the MSB employing over 47,000 production workers. MSB shipyards employ about 60 

percent of the total work force of the shipbuilding and repair industry. The remaining 40 percent 

are in smaller establishments with 10 or more employees (Maritime Administration 1999). As 

shown in Figure 4.1, the largest number of production workers are employed by shipyards of the 

smallest category. Over 29,000 workers are employed by nine active shipbuilders – this is more 

workers than the three other categories combined (15.7 thousand employees at 84 yards). 

According to the 1997 Census of Manufacturers data (the most recent Census data available), 

there were approximately 700 shipbuilding and repairing yards under SIC code 3731 (including 

both first and second-tier yards). The payroll for 1997 totaled $3.4 billion for a workforce of 

97,385 employees, and value of shipments totaled $10.6 billion. Based on this Census of

Manufacturers data, the industry is very labor intensive. The value of shipments per employee 

(a measure of labor intensiveness) is $108,600 which is about one third that of the steel 

manufacturing industry ($356,000 per employee) and only five percent that of the petroleum 

29

6.2 5.6

3.9

39

30

9

15

0

5

10

15

20

25

30

35

Active

Shipbuilders

Shipyards with

Build Positions

Repair

w/Drydocking

Topside Repair

Number of Employees 

(thousands)

0

5

10

15

20

25

30

35

40

45

Number of Shipyards

Figure 4.1. Number of Production Workers by Shipyard Type.

Source: Office of Shipbuilding and Marine Technology (2002) 
46

refining industry ($2.4 million per employee). It is the relatively few (but large) shipyards, 

however, that account for the majority of the industry’s employment and sales.13

As shown in Table 4.1, the geographic distribution of the shipbuilding industry is concentrated 

on the coasts. Of the 93 majors, over one-third (33 facilities) are located on the Gulf Coast, the 

majority of which are repair with drydocking. Another one-third is found on the East Coast with 

32 facilities, and the West Coast has 18 (again, mostly repair). 

Offshore Supply Vessels: Of particular importance to this report are the offshore supply 

vessels (OSV) – those that work solely to provide services to offshore oil and gas platforms. 

These services can include transportation of personnel, equipment and various supplies. One 

type of OSV, knows as PSVs, are involved in providing offshore drilling and production facilities 

with various supplies including equipment, pipes, lubricants, chemicals and drilling mud. They 

can also perform fire fighting as well as oil recovery operations in case of an oil spill at an 

offshore platform. The OSV category also includes vessels called “anchor handling tugs/supply 

vessels” (AHTS). These units spend a majority of their time working as supply vessels and only 

a small amount of time moving anchors. 

The supply boat fleet has increased significantly in the past 5 years. As seen in Figure 4.2, the 

GOM supply vessel fleet has increased by approximately 100 boats (35 percent) since 1996. 

This incorporates a net impact of 116 newbuilds, the influx of vessels to the GOM from foreign 

markets and the attrition of older, obsolete boats (Pickering et al. 2000). As of 2000, there were 

376 supply boats in the Gulf. Of these, 325 were being actively marketed. The remaining 51 

were either undergoing major upgrades, or had been removed from service and not actively 

marketed. 

 

13 Unless otherwise noted, this section is from: Office of Compliance, Profile of the Shipbuilding and 

Repair Industry (Washington D.C.: Office of Enforcement and Compliance Assurance, Environmental 

Protection Agency), 1997b, p. 3.

Table 4.1

Number of Shipyards by Type and Region

Active Shipyards with Repair with Topside

Shipbuilders Build Positions Drydocking Repair

East Coast 4 3 13 12

Gulf Coast 4 6 6 17

West Coast 1 2 7 8

Great Lakes 0 4 1 2

Non-Contiguous 0 0 3 0

Total 9 15 30 39

Source: Office of Shipbuilding and Marine Technology (2002) 
47

Although the traditional workhorse of the Gulf has been the standard 180 foot supply vessel, 

none of the boats built during this last cycle was less than 190 feet in length. Eighty-seven 

percent of newbuilds were 200 feet in length or greater. In fact, over half of the 116 newbuilds 

were at least 220 feet in length. “The increasing size of the newbuild fleet is directly related to 

the emergence of deepwater drilling in the GOM over the past four years” (Pickering et al. 

2000). 

The Gulf of Mexico supply vessel industry is very fragmented. There are a total of 24 boat 

operators in the Gulf. Sixteen of these operators own fleets of less than 10 boats. Nine of the 

operators own three boats or less. And, of these 24 operators, 6 are public companies and the 

other 18 are privately held. The public companies are: Tidewater, Trico Marine, Ensco Marine 

(subsidiary of Ensco International), Seacor Smit, Sea Mar (part of Nabors Industries) and

Seabulk Offshore (part of Hvide Marine). These six companies currently control 70 percent of 

the total GOM supply boat fleet (Figure 4.3) (Pickering et al. 2000).

277 265 249 247

264 277 279

303

334

361 376

0

50

100

150

200

250

300

350

400

11901991199219931994199519961997199819992000

Number of Vessels

Figure 4.2. Gulf of Mexico Supply Boat Total Fleet Size.

Source: Pickering et al. (2000) 
48

The companies with the youngest fleets are Hornbeck Offshore Services (7 boats with an

average age of 1.1 years), Otto Candies (5 boats averaging 1.2 years), Kim Susan (3 boats 

averaging 2 years), Edison Chouest (41 boats averaging 3.9 years) and Candy Fleet (8 boats 

averaging 4.5 years). These young fleets reflect a trend towards larger vessels as the average 

length for each fleet exceeds 200 feet (Pickering et al. 2000).

4.4 Regulations

This section discusses the Federal regulations that apply to this sector. The purpose of this 

section is to highlight and briefly describe the applicable regulations. The descriptions below 

are general information. Depending upon the nature or scope of the activities at a particular 

facility, these summaries may or may not necessarily describe all applicable regulatory

requirements.

Merchant Marine Act of 1920: More commonly known as the Jones Act, it requires that all 

merchandise being transported by water between U.S. points must travel in vessels that are 

built in the United States, crewed by U.S. mariners and owned by U.S. citizens. It even restricts 

foreign cruise ships from transporting passengers between U.S. ports. The purpose of the 

Jones Act is to maintain a shipbuilding and ship repair industrial base, a trained merchant 

mariner manning pool, and assets to respond in times of national security emergencies. The 

U.S. Customs Service has direct responsibility for enforcing the provisions of the Jones Act. 

The Jones Act has long been supported as it has generated jobs in all 50 states and is similar to 

the policies and laws of almost 50 foreign nations that also reserve their coastwide shipping and 

passenger trades for their domestic fleets. It keeps shipping and shipbuilding assets under U.S. 

control, subject to all U.S. laws and standards, and provides essential services in U.S. coastal 

states and waters and to the economies of Alaska, Hawaii and Puerto Rico. “Nationwide there 

are more than 37,000 vessels in the Jones Act fleet generating nearly 125,000 jobs, 80,000 of 

Figure 4.3. Supply Boat Market Share by Vessels in the Gulf of Mexico.

Source: Pickering et al. (2000) 

Sea Mar

7%

Seacor Smit

7%

Seabulk

6%

Ensco Marine

7%

Other

Tidewater 19%

30%

Trico Marine

13%

Chouest

11%
49

which are shipboard. The Jones Act fleet represents a $26 billion private sector investment in 

vessels and infrastructure and routinely moves more than 1 billion tons of cargo and 100 million 

passengers each year” (Maritime Cabotage Task Force 2003).

Critics of the Jones Act, however, state that it is an antiquated law that places severe

restrictions on U.S. businesses and costs the economy billions of dollars because of its anticompetitive inefficiencies. Jones Act requirements inhibit the movement of grain by water within 

the U.S, especially in areas with insufficient rail service – U.S. agriculture bears the increased 

cost of transportation. This in turn affects rail congestion problems and reduces competition 

within the U.S. shipping market. Numerous attempts have been made to reform or repeal the 

Jones Act, none of which have been successful.

Resource Conservation and Recovery Act (RCRA): A material is classified under RCRA as 

a hazardous waste if the material meets the definition of solid waste, and that solid waste 

material exhibits one of the characteristics of a hazardous waste or is specifically listed as a 

hazardous waste. A material defined as a hazardous waste may then be subject to Subtitle C 

generator, transporter, and treatment, storage, and disposal facility requirements. The

shipbuilding and repair industry must be concerned with the regulations addressing all of 

these.14

Several common shipyard operations have the potential to generate RCRA hazardous wastes. 

Some of these wastes are identified below by process. 

• Machining and Other Metalworking

- Metalworking fluids contaminated with oils, phenols, creosol, alkalies,

phosphorus compounds, and chlorine

• Cleaning and Degreasing

- Solvents

- Alkaline and Acid Cleaning Solutions

- Cleaning filter sludges with toxic metal concentrations

• Metal Plating and Surface Finishing and Preparation

- Wastewater treatment sludges from electroplating operations

- Spent cyanide plating bath solutions 

- Plating bath residues from the bottom of cyanide plating baths 

- Spent stripping and cleaning bath solutions from cyanide plating operations 

• Surface Preparation, Painting and Coating

- Paint and paint containers containing paint sludges with solvents or toxic metals 

concentrations

- Solvents 

- Paint chips with toxic metal concentrations

- Blasting media contaminated with paint chips

 

14 The remainder of this section is taken from: Office of Compliance, Profile of the Shipbuilding and 

Repair Industry (Washington D.C.: Office of Enforcement and Compliance Assurance, Environmental 

Protection Agency), 1997, p. 93-96.
50

• Vessel Cleaning

- Vessel sludges

- Vessel cleaning wastewater

- Vessel cleaning wastewater sludges

• Fiberglass Reinforced Construction

- Solvents

- Chemical additives and catalysts

Shipbuilding and repair facilities may also generate used lubricating oils which are regulated 

under RCRA but may or may not be considered a hazardous waste.

United States Code, Title 10, Section 7311: Title 10, Section 7311 of the U.S. Code applies 

specifically to the handling of hazardous waste (as defined by RCRA) during the repair and 

maintenance of naval vessels. The Code requires the Navy to identify the types and amounts of 

hazardous wastes that will be generated or removed by a contractor working on a naval vessel 

and that the Navy compensate the contractor for the removal, handling, storage, transportation, 

or disposal of the hazardous waste. The Code also requires that waste generated solely by the 

Navy and handled by the contractor bears a generator identification number issued to the Navy; 

wastes generated and handled solely by the contractor bears a generator identification number 

issued to the contractor; and waste generated by both the Navy and the contractor and handled 

by the contractor bears a generator identification number issued to the contractor and a

generator identification number issued to the Navy.

Clean Air Act: Under Title III of the 1990 Clean Air Act Amendments (CAAA), EPA is required 

to develop national emission standards for 189 hazardous air pollutants (NESHAP). EPA is 

developing maximum achievable control technology (MACT) standards for all new and existing 

sources. The National Emission Standards for Shipbuilding and Repair Operations (Surface 

Coating) were finalized in 1995 and apply to major source shipbuilding and ship repairing 

facilities that carry out surface coating operations. Shipyards that emit ten or more tons of any 

one HAP or 25 or more tons of two or more HAPs combined are subject to the MACT

requirements. The MACT requirements set VOC limits for different types of marine coatings 

and performance standards to reduce spills, leaks, and fugitive emissions. EPA estimates that 

there are approximately 35 major source shipyards affected by this regulation. Shipbuilding and 

repair facilities may also be subject to National Emissions Standards for Asbestos. 

Both NESHAPs require emission limits, work practice standards, record keeping, and reporting. 

Under Title V of the CAAA 1990, all of the applicable requirements of the Amendments are 

integrated into one federal renewable operating permit. Facilities defined as "major sources" 

under the Act must apply for permits within one year from when EPA approves the state permit 

programs. Since most state programs were not approved until after November 1994, Title V 

permit applications, for the most part, began to be due in late 1995. Due dates for filing 

complete applications vary significantly from state to state, based on the status of review and 

approval of the state’s Title V program by EPA. 

A facility is designated as a major source for Title V if it releases a certain amount of any one of 

the CAAA regulated pollutants (SOx, NOx, CO, VOC, PM10, hazardous air pollutants, extremely 

hazardous substances, ozone depleting substances, and pollutants covered by NSPSs)

depending on the region's air quality category. Title V permits may set limits on the amounts of 
51

pollutant emissions; require emissions monitoring, and record keeping and reporting. Facilities 

are required to pay an annual fee based on the magnitude of the facility's potential emissions. 

Clean Water Act: Shipbuilding and repair facility wastewater released to surface waters is 

regulated under the CWA. National Pollutant Discharge Elimination System (NPDES) permits 

must be obtained to discharge wastewater into navigable waters. Facilities that discharge to a 

POTW may be required to meet National Pretreatment Standards for some contaminants. 

General pretreatment standards applying to most industries discharging to a POTW are

described in 40 CFR Part 403. In addition, effluent limitation guidelines, new source

performance standards, pretreatment standards for new sources, and pretreatment standards 

for existing sources may apply to some shipbuilding and repair facilities that carryout

electroplating or metal finishing operations. 

Stormwater rules require certain facilities with stormwater discharge from any one of 11

categories of industrial activity defined in 40 CFR 122.26 be subject to the stormwater permit 

application requirements. Many shipbuilding and repair facilities fall within these categories. 

Required treatment of stormwater flows are expected to remove a large fraction of both

conventional pollutants, such as suspended solids and biochemical oxygen demand (BOD), as 

well as toxic pollutants, such as certain metals and organic compounds.

Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA):

The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) and 

the Superfund Amendments and Reauthorization Act of 1986 (SARA) provide the basic legal 

framework for the federal “Superfund” program to clean up abandoned hazardous waste sites. 

Metals and metal compounds often found in shipyards’ air emissions, water discharges, or 

waste shipments for off-site disposal include chromium, manganese, aluminum, nickel, copper, 

zinc, and lead. Metals are frequently found at CERCLA's problem sites. When Congress 

ordered EPA and the Public Health Service's Agency for Toxic Substances and Disease

Registry (ATSDR) to list the hazardous substances most commonly found at problem sites and 

that pose the greatest threat to human health, lead, nickel, and aluminum all made the list.

4.5 Industry Trends and Outlook

The 1980's were dismal times for the U.S. shipbuilding industry. A combination of factors 

including a lack of a comprehensive and enforced maritime policy, failure to continue funding 

subsidies established by the Merchant Marine Act of 1936 and the collapse of the U.S. offshore 

oil industry, not only hurt the shipbuilding industry but all support industries such as small

shipyards and repair yards. Approximately 120,000 jobs for shipyard workers and shipyard 

suppliers were lost. 

At its height in the mid-1970s, the industry held a significant portion of the international

commercial market while maintaining its ability to supply all military orders. Then in the 1980s, 

new ship construction, the number of shipbuilding and repair yards, and overall industry

employment decreased sharply. Especially severe was the decline in the construction of 

commercial vessels at first tier shipyards – falling from about 77 ships (1,000 gross tons or 

more) per year in the mid-1970s to only about eight ships total through the late 1980s and early 

1990s. In the 1980s, the industry’s loss of the commercial market share was somewhat offset 

by a substantial increase in military ship orders. However, the industry entered the 1990s with a 

much smaller military market and a negligible share of the commercial market. The second tier 
52

shipyards and the ship repairing segment of the industry have also suffered in recent decades; 

however, the decline has not been as drastic (Office of Compliance 1997b). 

The U.S. shipbuilding and repairing industry’s loss of the commercial shipbuilding market has 

been attributed to a number of factors. First, a world wide shipbuilding boom in the 1970s 

created a large quantity of surplus tonnage which suppressed demand for years. Another 

significant factor reducing U.S. shipbuilding and repair industry’s ability to compete

internationally are the substantial subsidies that many nations provide to their domestic

shipbuilding and repair industries. Also, until 1980, over 40 percent of U.S.-built merchant ships 

received Construction Differential Subsidies (CDS) based on the difference between foreign and 

domestic shipbuilding costs. The program was eliminated in 1981, further reducing the 

industry’s competitiveness (Office of Compliance 1997b).

The U.S. government and the shipbuilding industry have made great strides in their efforts 

towards industry revitalization and market transformation. The industry is experiencing a come 

back, as shown in Figure 4.4. The number of commercial ships on order is slowly increasing 

from the lows of the early 1990s. One major stimulus has been the surge in activity relating to 

offshore exploration, drilling and servicing sectors. These shipyards are expected to prosper in 

the next decade (Maritime Administration 1999). 

Capital Investments: During FY 2002, the U.S. ship construction and ship repair industry 

invested more than $408 million in the upgrade and expansion of facilities (Figure 4.5). Much of 

this investment was to improve efficiency and competitiveness in the commercial shipbuilding 

arena. Improvements were made to update and convert shipyard facilities to be more

commercially viable. Examples of recent capital investments are new pipe and fabrication 

Figure 4.4. Commercial Shipbuilding Orderbook History.

* 2001 Data as of June 1, 2001.

Source: Maritime Administration (2002b) 

77

71

51

59

62

46

35

21

13 14

11

7

0 0 0

3 3

1 1

3

10

14 12

5

10

16 15

0

10

20

30

40

50

60

70

80

90

19751977197919811983198519871989199119931995199719992001

(Number of Ships)

*

77

71

51

59

62

46

35

21

13 14

11

7

0 0 0

3 3

1 1

3

10

14 12

5

10

16 15

0

10

20

30

40

50

60

70

80

90

19751977197919811983198519871989199119931995199719992001

(Number of Ships)

*
53

shops, drydock extensions, military work enhancement programs, automated steel process 

buildings and expanded design programs. Many of these improvements have been necessary 

due to the increased utilization of U.S. shipyards, particularly those along the Gulf Coast,

resulting from the resurgence of the Oil Patch Industry. In 2003, the industry planned to spend 

about $325 million in the upgrade and expansion of facilities, according to data received by the 

Maritime Administration. The industry's capital investments since 1970 have totaled

approximately $8.5 billion. The actual expenditures between 1985 and 2001, with the exception 

of 1990 and 2001, have consistently exceeded those planned (Office of Shipbuilding and Marine 

Technology 2002).

Other issues that may affect the future of shipbuilding in the United States, particularly along the 

Gulf Coast, include the following:

Maritime Policy: The debate over the Jones Act will continue. Supporters stress that before 

World War I, the majority of the United States’ trade was carried by foreign ships. As a result, 

shipping rates experienced a 2000 percentage increase when the war began. That shortage 

prompted Congress to pass the Jones Act, in an attempt to eliminate the country’s dependence 

on foreign ships. However, opponents of the Act claim that it places too much restriction on 

U.S. business and is anti-competitive. Whichever way this debate is decided, it will affect the 

shipbuilding industry more so than any other in the U.S. 

Oil Pollution Act of 1990: This legislation requires that all new liquid bulk vessels trading in 

U.S. waters be equipped with double hulls and that existing tankers without double hulls be 

retrofitted or be removed from oil production transportation. It is difficult to know the number of 

0

100

200

300

400

500

600

19901991199219931994199519961997199819992000200120022003

(Million $)

Actual

Planned

Figure 4.5. U.S. Shipbuilding and Repair Industry Capital Investments.

Source: Office of Shipbuilding and Marine Technology, (2002) 
54

tankers that will have to be rebuilt, scrapped or constructed as a result of this legislation. But by 

2015, a double hull will be required for all tankers entering a U.S. port. 

Financing: Title XI of the Merchant Marine Act (and later amended) started a National

Shipbuilding Initiative program to support the U.S. shipbuilding industry and help establish it as 

a self-sufficient internationally competitive industry. The U.S. government insures and

guarantees full payment to the lender of the unpaid principal and interest of the obligation in the 

event of default by the vessel owners or general shipyard facility. As of September 2001, Title 

XI guarantees in force totaled about $4.9 billion, covering 871 vessels and 89 individual ship 

owners. In 2001, Title XI applications totaling approximately $730 million in loan guarantees 

were approved – covering construction of 295 vessels (Maritime Administration 2001b). “The 

availability of long-term Title XI guarantees for vessels constructed in U.S. shipyards will

continue to be a major factor in the revitalization of commercial shipbuilding in U.S. shipyards. 

The U.S. shipbuilding industry has to make significant strides in building efficient ships at lower 

prices with on-time deliveries for the Jones Act trade to demonstrate to the international market 

its ability to produce high quality commercial vessels” (Industry Pro 2000).

Other Opportunities: The U.S. shipbuilding industry has a bright future – significant capital 

investment has been made to enhance productivity; and shipbuilding companies have been 

working with the federal government to increase production and position in the international 

arena. In addition, opportunities are available in each of the following growing markets: 

• Casino Boat Market: River boat gambling has offered construction opportunities for 

small to medium boat yards. Obviously, the more states that legalize gambling, the 

greater impact on the shipbuilding industry.

• Ferry Boat Market: Ferries continue to be a popular secondary mode of

transportation. ISTEA offered incentives for ferry construction through federal 

grants. It was hoped that this would help to alleviate the number of automobiles in 

congested urban areas. Again, small and medium shipyards have opportunities in 

this area.

• Offshore Market: The offshore market is undergoing a rapid expansion since the 

marked decline of the 1980's. Advancements in deep-water drilling has encouraged 

exploration, leading to greater production and activity in the coastal areas. The need 

for supply and other types of industry support vessels has increased. With changing 

technology has come the need for more sophisticated and higher capacity vessels.

• River Tonnage Market: The bulk of the nation’s barges and towboats operate in the 

Mississippi River and the Gulf Intracoastal Waterway. As a greater amount of goods 

and commodities are transported through this network, Louisiana shipyards are in a 

good position to offer services to that industry. 

Offshore Supply Vessels: In 1998, the OSV industry experienced a downturn and a great 

deal of consolidation. Numerous small players left the OSV business due to bankruptcy, asset 

sales to larger competitors or asset sales outside the industry. “We estimate that more than half 
55

of the smaller boat operators that operated three or fewer boats in the last cycle are no longer in 

business.”15 

As shown in Figure 4.6, the market share for several major companies has experienced

significant changes since 1997. The most noticeable change is the decline in Tidewater’s 

market share from 42 percent in 1997 to 30 percent in 2000. This is a result of Tidewater’s 

restraint from building during the last upswing of newbuilds. Chouest gained the most in terms 

of market share – almost doubling from 6 to 11 percent in three years. Of the public companies, 

only Sea Mar and Trico Marine did not experience market share erosion. Trico’s market share 

gain was the direct result of industry consolidation – Trico made four acquisitions and added a 

total of 24 boats. 

Fleet Age: The Gulf supply boat industry does not have a young fleet. Nearly 40 percent of the 

entire fleet is at least 20 years old, reflecting the massive fleet expansion that occurred in the 

late 1970s and early 1980s. Only 26 percent of the fleet is 10 years old or younger. A majority 

of the younger boats were built during the 1996 and 1999 newbuild cycle. 

Combined with the scrappage of obsolete, older vessels, the recent significant newbuild 

program has decreased the average age of the Gulf supply vessel fleet by roughly two years. 

The average age of the fleet in 1997 was 17.9 years. As of 2000, the average age of the total 

fleet in the Gulf of Mexico is 15.7 years. 

 

15 Unless otherwise noted, the information in this section is taken from: Daniel R. Pickering, Jennifer 

Hu, and Justin J Tugman, The Gulf of Mexico Supply Vessel Industry, A Return to the Crossroads,

(Houston: Energy Industry Research, Simmons & Company International), November 2000.

Figure 4.6. Percentage of Total Gulf of Mexico Fleets for Large Companies (more than 10 

Vessels).

Source: Pickering et al. (2000) 

Cheramie 

Botruc

4%

Chouest

11%

Ensco

7%

Seabulk

6%

Seacor

7%

Sea Mar

7%

Tidewater

30%

Trico 

Marine

13%

Other

15%

Cheramie 

Botruc

5% Chouest

6%

Ensco

8%

Seabulk

8%

Seacor

10%

Sea Mar

4%

Tidewater

42%

Trico 

Marine

12%

Other

5%

1997 2000

Cheramie 

Botruc

4%

Chouest

11%

Ensco

7%

Seabulk

6%

Seacor

7%

Sea Mar

7%

Tidewater

30%

Trico 

Marine

13%

Other

15%

Cheramie 

Botruc

5% Chouest

6%

Ensco

8%

Seabulk

8%

Seacor

10%

Sea Mar

4%

Tidewater

42%

Trico 

Marine

12%

Other

5%

Cheramie 

Botruc

4%

Chouest

11%

Ensco

7%

Seabulk

6%

Seacor

7%

Sea Mar

7%

Tidewater

30%

Trico 

Marine

13%

Other

15%

Cheramie 

Botruc

5% Chouest

6%

Ensco

8%

Seabulk

8%

Seacor

10%

Sea Mar

4%

Tidewater

42%

Trico 

Marine

12%

Other

5%

1997 2000
56

Recovery in Drilling Demand: The primary driver of supply vessel demand in the Gulf is 

offshore rig activity. As discussed throughout this report, the offshore drilling industry,

especially in deepwater, is booming. This surge in rig activity has been the most important 

driver for improvements in supply vessel utilization. 

The number of drilling rigs capable of drilling in over 3,000 feet of water has quadrupled since 

1996. However, in comparison to the shallower areas of the Gulf, support of deepwater drilling 

requires a significantly enhanced supply boat. 

• Larger liquid mud capacity: In deepwater, the well extends from the ocean surface 

to the ocean floor and then into the earth. The wells also have risers with much 

larger diameters than shallow water wells. Thus, more drilling mud is required to fill 

the wellbore and riser. This is usually 3,000 to 4,000 barrels and can be as much as 

6,000 barrels in water depths over 5,000 ft. Thus, deepwater supply boats need 

large liquid mud capacities. A standard 180 ft supply vessel typically has a liquid 

mud capacity of 1,000 to 1,600 barrels. 

• Dynamic positioning capability: Deepwater drilling rigs generally operate further 

away from shore than conventional shallow water units. Weather patterns can be 

violent and the sea conditions are typically rougher. With total deepwater drilling 

costs at $200,000 to $500,000 per day, it is very costly for the drilling process to be 

interrupted because weather conditions limit the transfer of supplies or drilling mud 

from a boat to the rig. In order for a supply vessel to safely maintain its position near 

a deepwater rig, dynamic positioning (DP) is required. With DP capability, a supply 

vessel uses global positioning satellites to determine an exact location and small 

engines or thrusters to maintain the boat’s position. Although most older supply 

vessels are not dynamically positioned, this function can be added, but often times at 

costs that make the upgrade uneconomical.

Assuming no new capacity additions from newbuilds or vessels returning from international 

markets tip the scales toward a softer market, “the GOM deepwater market is the place to be for 

domestic supply vessel operators” (Pickering et al. 2000).

4.6 Inventory of Major Gulf Coast Facilities

The American Shipbuilding Association is the professional organization for those in the industry 

who are capable of constructing mega vessels which are in excess of 400 ft in length and weigh 

in excess of 20,000 DWT. For this reason, their membership consists of only six companies. 

Of those six, two have a presence in the Gulf of Mexico. Both Avondale Shipyard of New 

Orleans, LA and Ingalls of Pascagoula, MS have enormous capabilities and expertise in the 

design, construction and repair of vessels. This highly developed level of specialized

knowledge has made these two companies ideal contractors for the nation’s defense efforts. 

Therefore, most of the work that has been accomplished in these two yards has been for the 

U.S. Military.

The existence of enormous commercial needs has lead to the development of a very large 

number of boat and barge builders. These companies direct their effort toward the specific 

requirements of industries such as the offshore oil and gas industry. Therefore, the vessels 

they produce are not as large as those being built by the two previously mentioned companies 
57

who are building primarily for the national defense. However, as the oil and gas industry has 

evolved and become more sophisticated, particularly with deep-water drilling, so too has the 

capability of this segment of the boat building industry. Many of these companies are now 

producing ships in the 300 ft range.

Based on an inventory conducted as part of the development of a GIS database for this project, 

we recorded 162 shipbuilding and repair facilities of various sizes located within the Gulf region 

which support the oil and gas industry. Eighty-two facilities are located in Louisiana, 35 in 

Texas, 17 in Mississippi, 15 in Florida, and 13 in Alabama. A list of the primary shipyards 

present in the Gulf is provided in Table 4.2.

Table 4.2

Primary Shipyards in the Gulf Region which Support the 

Offshore Oil and Gas Industry (2000)

Texas City

Bludworth Marine LLC dba Vessel Repair Houston

Carotex, Inc. Port Arthur

Channel/Lynchburg Shipyard Highlands

Channel Shipyard Company, Inc. Highlands

First Wave Marine/Newpark Brady Island Facility Galveston

First Wave Marine/Newpark Greens Bayou Facility Houston

First Wave Marine/Newpark Galveston Island Facility Galveston

First Wave Marine/Newpark East Pelican Island Facility Galveston

First Wave Marine/Newpark Pasadena Facility Pasadena

First Wave Marine/Newpark West Pelican Island Facility Galveston

Bollinger Houston Houston

Bollinger Texas City Texas City

Halter TDI - Central Port Arthur

Halter TDI - Dockyard Port Arthur

Halter TDI - North Port Arthur

Halter TDI - Orange Orange

Halter TDI - Pier I Orange

Halter TDI - Sabine Pass Sabine Pass

Halter TDI - South Sabine Pass

Southwest Shipyard, L.C. Channelview

Trinity Marine Industries Beaumont Facility Beaumont

Trinity Marine Industries Orange Facility Orange

Trinity Marine Products Dallas

Louisiana

Bollinger Algiers Algiers

Bollinger Amelia Repair Amelia

Bollinger Chand Corporation Mathews

Bollinger Fourchon Golden Meadow

Bollinger Larose Larose

Bollinger Marine Fabricators Amelia

Bollinger Morgan City Morgan City

Bollinger Quick Repair Harvey
58

Table 4.2

Primary Shipyards in the Gulf Region which Support the 

Offshore Oil and Gas Industry (2000) (Continued)

Louisiana (Continued) City

Bollinger Shipyards Lockport Lockport

Bollinger Calcasieu Lake Charles

Bollinger Gretna Gretna

Bollinger Gulf Repair New Orleans

Channel Shipyards, Inc. New Orleans

Avondale Shipyards New Orleans

Edison Chouest Offshore Galliano

North American Shipbuilding Larose

North American Fabricators Houma

Halter Equitable New Orleans

Halter Lockport Lockport

Leevac Shipyards, Inc. Jennings

L. M. S. Shipmanagement, Inc. New Orleans

L. M. S. Shipmanagement, Inc. Lafitte

L. M. S. Shipmanagement, Inc. Algiers

McDonough Marine Services Metairie

T. T. Barge Services Donaldsonville

T. T. Barge Services Westwego

T. T. Barge Services Hahnville

T. T. Barge Services Harahan

Trinity Marine Products, Inc. Madisonville

Trinity Marine Products, Inc. Baton Rouge

Trinity Marine Products, Inc. Brusly

Mississippi

Halter Marine Group Gulfport

Halter Gulf Coast FAB Pearlington

Halter Moss Point Marine Moss Point

Halter Pascagoula Pascagoula

Halter Gulfport Marine Gulfport

Mississippi Marine Corporation Greenville

Superior Boat Works Greenville

Ingalls Shipyard Pascagoula

Litton Ship Systems Pascagoula

Alabama

Alabama Shipyard Mobile

Atlantic Marine, Inc. Mobile

Bender Shipbuilding & Repair Company Mobile

Harrison Brothers Dry Dock & Repair Yard Mobile

Henry Marine Service Mobile
59

Table 4.2

Primary Shipyards in the Gulf Region which Support the 

Offshore Oil and Gas Industry (2000) (Continued)

Florida City

Atlantic Marine, Inc Jacksonville

Friede Goldman Halter Panama City

Sun State Marine Services, Inc. Green Cove Springs

The following are brief descriptions of some of the major shipyards along the Gulf of Mexico:

Bollinger Shipyards

P.O. Box 250

8365 Hwy. 308 South 

Lockport, LA 70374

Phone: 504-532-2554 

Fax: 504-532-7225

webmaster@bollingershipyards.com

Begun in 1946, the company specializes in the repair, conversion and new construction of a 

wide variety of small to medium-sized offshore and inland vessels. It primarily addresses the 

energy, commercial and government marine markets in the Gulf of Mexico region.

The company currently operates fourteen shipyards located throughout South Louisiana and 

Texas with direct access to the central Gulf of Mexico. With 42 dry docks ranging in capacity 

from 100 tons to 22,000 tons, Bollinger provides a wide variety of dry-docks and services for 

both shallow and deepwater vessels and rigs.

Locations include the following: 

 

 Bollinger Algiers Bollinger Gulf Repair Bollinger Quick Repair

 Bollinger Amelia Repair Bollinger Houston Bollinger Shipyards Lockport

 Bollinger Calcasieu Bollinger Larose Bollinger Texas City

 Bollinger Fourchon Bollinger Marine Fabricators Chand

 Bollinger Gretna Bollinger Morgan City NorthShore Engineering

Bollinger has established a range of designs and has the capability of developing new designs 

and/or existing design modification to meet specific customer requirements. The designs are 

divided into six different categories: Patrol Craft, Offshore Supply Vessels, Liftboats, Barges, 

Specialties and Tugs.
60

Harrison Brothers Dry Dock & Repair Yard, Inc.

P.O. Box 1843

200 6th Street

Blakely Island

Mobile, AL 36633-1843

Phone: 334-432-4606 

Fax: 334-438-3188

Harrison Brothers is an established shipyard engaged in the repair of tugboats, barges, supply 

boats, small ships, and other commercial vessels. It has been in operation for 103 years. Their 

drydocks can handle vessels up to 300 feet and 2000 tons. They also offer dockside repair

facilities for floating repairs. Ancillary repair equipment includes a host of cranes, derricks, and 

shift tugs.

First Wave/Newpark Shipyards

2102 Broadway

Houston. TX 77012

Phone: 713-847-4600

Fax: 713-847-4601

info@fwav.com

FirstWave/Newpark Shipbuilding provides repair, conversion, new construction, and related 

services for barges, boats, ships, offshore rigs, and other vessels in the offshore and inland 

marine industries. It operates a network of six yards, three in the Houston Ship Channel area 

and three in the Galveston area.

The company's Galveston Division is headquartered at the East Pelican Island Facility. This 

yard is configured for mobile offshore rig and drillship repairs and conversions. A 7,500 ton 

drydock located there accommodates OSVs, small ships, barges and other vessels.

With more than twenty haul-out facilities (consisting of drydocks and marine railways), the

Houston Division can handle large volumes and a variety of shipyard work. The company is 

also equipped to provide fabricated products and services, with 280,000 sq ft of manufacturing 

space under roof and crane capacity up to 500 tons at the West Pelican Island Facility in 

Galveston.

An environmental services division in Houston offers gas-freeing services to its shipyard

customers as well as non-hazardous wastewater treatment and other environmental services to 

a variety of industrial customers.

New construction is directed toward inland barges, tugboats, pushboats, dredges, ferries,

specialty vessels and rig components. Repairs, conversions and modifications are also offered 

for offshore drilling and production rigs and rig components, inland barges, offshore supply 

vessels, tugboats, pushboats and other inland river boats, dredges, ferries, government vessels, 

specialty vessels, FPSOs, and cargo and passenger ships.
61

Edison Chouest Offshore (ECO)

P. O. Box 310

Galliano, LA 70354

Webmaster@eco.chouest.com

Louisiana Edison Chouest Offshore (ECO) was founded in 1960, has doubled in size since

1993, and now has over 3,000 employees worldwide. Design and construction capabilities have 

made ECO prominent in the offshore boat service industry. Chouest has chosen a unique 

approach by designing, building, owning, and operating each of their vessels while leased to 

clients. Today, ECO has under charter the largest number of privately owned and operated 

special-purpose vessels to the U.S. Government. The company also owns and operates the 

largest independently owned fleet of seismic and research vessels in the world. ECO owns and 

operates a growing fleet of new generation offshore deep-water service vessels supporting over 

90 percent of the U.S. Gulf deepwater market. ECO's high-tech, high-capacity offshore vessels 

range from 87 ft to 320 ft.

• North American Shipbuilding in Larose Louisiana (an ECO affiliate)

North American Shipbuilding (NAS) was founded in 1974, and has built many

specialized offshore vessels. Since it was purchased by ECO, it has designed and 

constructed vessels only for ECO and affiliated companies. NAS built the first U.S. 

Antarctic icebreaking research vessel, the largest and most powerful anchor

handling vessel in the U.S. fleet, the first dynamically positioned vessel in the U.S. 

fleet, the world's first floating production system installation vessel, and the largest 

water throw capacity vessel in the U.S. fleet. It has a formal welding training 

program and on the job apprenticeship training for all other trades.

• North American Fabricators in Houma Louisiana (an ECO affiliate)

 

Since its founding in 1996, North American Fabricator (NAF) has developed into a 

state-of-the-art, world-class shipbuilding facility. NAF currently employs over 250 

shipyard workers who build modern, highly specialized offshore supply vessels 

from 190 feet long and up. NAF's first vessel delivered was the C-Commander, the 

largest offshore supply vessel in the U.S. fleet at that time, at 240 ft long and 56 ft 

wide. NAF's new construction projects will be designed to accommodate

deepwater oil and gas production and global research expeditions.

Litton Ship Systems

Litton Ship Systems (LSS), headquartered in Pascagoula, Mississippi, was formed on August 1,

1999, and includes Litton Ingalls Shipbuilding and the Litton Ship Systems Full Service Center, 

also in Pascagoula, and Litton Avondale Industries, in New Orleans, Louisiana, and Gulfport, 

Mississippi. LSS employs more than 17,000 shipbuilding professionals, primarily in Mississippi 

and Louisiana, and is one of the nation's leading full service systems companies for the design, 

engineering, construction, and life cycle support of major surface ships for the U.S. Navy, U.S. 
62

Coast Guard and international navies, and for commercial vessels of all types. Northrop 

Grumman acquired Litton Industries in 2001.

Avondale\The Shipyards Division

P.O. Box 50280

New Orleans, LA 70150-0280

5100 River Road

Avondale, LA 

Phone: 504-436-2121

Fax: 504-436-5200

www.avondale.com

Avondale's main shipyard is located on the Mississippi River twelve miles upriver from the Port 

of New Orleans. This facility includes two separate construction areas. One construction area 

has three building positions and utilizes a 900-foot floating launch platform. The second area 

has five building positions where ships are side-launched into the river. These integrated 

assembly areas are supported by a state-of-the-art marine steel fabrication facility. Included at 

the facility are a fully-equipped machine shop, semi-automated pipe shop, electrical shop, and 

sheet-metal shop.

Since 1982, Avondale has used modular construction technology to build ships. This technology 

was acquired from a leading Japanese shipbuilder and has been mastered by Avondale's work 

force. Simply stated, modular construction consists of building 150 to 200 modules or units and 

completely outfitting them with pipe, ventilation systems, etc. The modules are then joined just 

prior to launching. 

Litton Avondale Industries in New Orleans, Louisiana, and Gulfport, Mississippi, is the prime 

contractor for the Navy/Marine Corps Team's SAN ANTONIO (LPD17) Class of amphibious 

assault ships. Avondale is also building seven T-AKR Ro/Ro Sealift ships for the U.S. Navy, 

with three delivered and four currently under construction. These Sealift ships are 950 feet 

long, making them second in size only to aircraft carriers in the U.S. Navy's fleet. Avondale is 

also building three double-hull oil tankers (the first to be built in the U.S.), for ARCO Marine. 

These giant ships are world's most environmentally safe product tankers.

Ingalls Shipyard

P.O. Box 149

Pascagoula, MS 39568-0149

1000 Access Road

Pascagoula, MS 39567

Phone: 228-935-1122 

Fax: 228-935-1126

www.ingalls.com

Litton Ingalls Shipbuilding Headquartered in Pascagoula, Mississippi, is the sole builder of the 

Navy/Marine Corps Team's WASP (LHD 1) Class of large-deck multipurpose amphibious

assault ships, which operate as the centerpiece of an Amphibious Ready Group (ARG). Ingalls
63

is one of two builders of the Navy's ARLEIGH BURKE (DDG 51) Class of Aegis guided missile 

destroyers, which provide primary antiair protection for the fleet. Currently, Ingalls is engaged in 

the production of the first major cruise ships built in the U.S. in more than 40 years.
65

5.0 SUPPORT AND TRANSPORT FACILITIES

5.1 Introduction

Offshore oil and gas activities are supported by a considerable and diverse onshore supply and 

support logistics train. Support activities range from products and services such as engine and 

turbine construction and repair, electric generators, chains, gears, tools, pumps, compressors, 

and a variety of other tools and equipment. Additionally, drilling muds, chemicals, and fluids are 

produced, and transported from onshore support facilities. Many types of transportation 

vessels, including helicopters, are used to transport workers, equipment, and materials to and 

from offshore platforms. 

In the past, a large number of these activities were “internal” to offshore oil and gas firms. Over 

time, more and more of these activities have been employed on a contract service basis. 

Today, the majority of onshore support and transportation services are provided by outside third 

parties. Downsizing and specialization have been the primary reasons for utilizing these

services on a contract basis. Industry downsizing, in particular, has reduced the numerous 

layers associated with oil and gas operations by many offshore producers. The use of contract 

services allows producers to utilize supply, transport, and logistics resources on an “as needed 

basis.” Utilizing these services on a contract basis gives offshore producers a significant degree 

of flexibility and allows them to keep costs down during periods of oil and gas commodity price 

downturns.

Onshore support and transportation services are employed by major and independent

producers alike. While the support sector of the industry is very heterogeneous in nature, all 

firms that operate in this sector share one common problem: their business, profits, and

earnings are highly dependent on the cyclical nature of the oil and gas industry. As will be 

discussed in greater detail later, this dependency has led to two different survival tactics by 

support and transportation firms in the Gulf: concentration and diversification. Concentration 

has occurred from general merger and acquisition activity, while diversification has resulted 

from taking on a broader number of support and service activities to dampen earnings impacts 

from falling oil and gas prices.

5.2 Description and Typical Facilities

General Support Facilities: Support facilities are diverse and, depending upon function, can 

take on a number of different characteristics. Many, however, have similar features such as 

being located at, or near, a marine port facility. Ports, in addition to serving as points of

disembarkment, tend to have physical attributes that complement support activities. Moreover, 

business practices at most ports are directed at developing and providing the necessary

infrastructure to support these types of activities. For the support and transport sector of the oil 

and gas industry, important physical infrastructure attributes of ports include:

• Protected wharfs, docks, and drydocks;

• Storage and demurrage facilities;

• Crew housing;

• Intermodal transportation access (i.e., roads, inter-coastal waterway, railways);
66

• Communication facilities/equipment; and,

• Workshops and machine and tooling shops.

Repair and Maintenance Yards: A significant portion of repair and maintenance support work 

that is conducted at these facilities is associated with maintaining vessels and equipment for 

drilling and production activities. Specific repair methods vary from job to job in both time and 

scope. Jobs can last from one day to over a year. Repair jobs often have severe time

constraints requiring work to be completed as quickly as possible in order to get the equipment 

back to service. This is particularly true during periods of high oil and gas prices, where working 

equipment is of high value. During periods of low oil and gas prices, repairs may be allowed to 

linger over longer periods of time, since equipment may be unneeded in the field.

In many cases, a number of tasks are pre-fabricated and then taken offshore for final assembly 

and repair. This can often be the case with such activities as piping, ventilation, electrical and 

other machinery. Typical maintenance and repair operations include:16

• Blasting and repainting the ship hulls, freeboard, superstructure, and interior tanks 

and work areas;

• Major rebuilding and installation of machinery such as diesel engines, turbines,

generators, pump stations, etc;

• Systems overhauls, maintenance and installation (e.g., piping system flushing,

testing and installation);

• System replacement and new installation of systems such as navigational systems, 

combat systems, communication systems, updated piping systems, etc.;

• Propeller and rudder repairs, modification, and alignment; and,

• Creation of new machinery spaces through cut outs of the existing steel structure 

and the addition of new walls, stiffeners, vertical, webbing, decking, etc.

Supply Bases: Supply bases can range from large yards, offering all kinds of service including 

full logistics management, to smaller shops that supply one or many of the items needed on an 

offshore platform or marine vessel. From strategic locations along the Gulf, larger supply 

companies who offer supply chain management services move equipment and supplies from 

land-based supply houses to offshore drilling platforms. Other, smaller suppliers act more or 

less like a retail store, supplying anything from crane rentals, warehouse space, trailer rentals, 

and dispatch services, to engine parts, fuel, navigation tools, potable water, and lubricants 

including, motor oil, hydraulic oil, natural gas compressor oils, grease, gear oil, and synthetics. 

Crew Services: A number of companies provide services to the crews that live on the offshore 

rigs. These companies provide catering – delivering and serving hot meals – and laundry, 

cleaning and maintenance services for crew barracks. A number of companies also provide onsite paramedics – they are not simply there to wait for someone to become ill or injured, but 

 

16In part from: Office of Compliance, Profile of the Shipbuilding and Repair Industry (Washington 

D.C.: Office of Enforcement and Compliance Assurance, Environmental Protection Agency), 1997b, p. 

20-21.
67

rather, they are part of the crew, offering an additional service which improves operational 

efficiency and productivity. 

Heliports: Heliports are centralized locations for which fixed and rotary wing aircraft (i.e., 

helicopters) are disembarked for offshore service. Helicopters move crew and equipment to 

offshore areas. Supply boats are typically used for short-haul service while helicopters are the 

primary means of transportation for distances of 150 to 175 miles out into the Gulf 

(approximately one and a half hours). This would include most deepwater platforms and

facilities (Murphy 1990).

Heliports are typically located at small and medium sized regional airports throughout the Gulf of 

Mexico. There can be main and auxiliary (or remote) heliport facilities. Main facilities, usually 

located at regional airports, host most of the main aircraft hangers, aircraft repair yards, as well 

as administrative offices. Over the past several years, helicopter and air transportation has

become concentrated with private contract firms. Individual oil and gas companies still own and 

operate company aircraft, but are increasingly turning to third parties to perform these tasks.

There are three main independent providers of air transportation services: Air Logistics (New 

Iberia, Louisiana); PHI, Inc (Lafayette, Louisiana)17; and Evergreen Helicopter, Inc. (Galveston, 

Texas).18 Each company operates numerous locations along the Gulf in addition to those 

activities conducted at their main headquarters. The primary business of all three is to provide 

crew and equipment transportation services to offshore oil and gas companies.

Air Logistics and Evergreen Helicopter maintain a fleet of 170 fixed and rotary wing aircraft 

each. PHI, the largest provider of transportation service in the Gulf, maintains a fleet of 300 

helicopters and operates the largest heliport in North America with 46 helipads in Morgan City, 

Louisiana. All three companies maintain aircraft ranging from Bell 212s and 206s, the 

workhorse of the industry, to heavy duty Sikorsky S-76s which are also used in medical air 

transportation.

At the height of drilling activity, from 1981 to 1983, up to 100,000 workers a day were being 

transported back and forth from oil and gas drilling and production platforms (Murphy 1990). 

Shortly afterwards, the number dropped to around 25,000 to 30,000 and today, estimates range 

in the 16,000 to 20,000 range. One factor leading to the different transport levels is the size of

the average crew typically operating in the Gulf. During the drilling heydays, drilling crews 

typically ranged from 30 to 50 people. However, today in a mostly production-oriented 

environment, production crews are much smaller, in the 2 to 6 person range.

Based on an inventory conducted as part of the development of a GIS database for this project, 

247 heliport facilities that support the oil and gas industry were recorded within the Gulf region; 

122 are located in Texas, 81 in Louisiana, 34 in Florida, 6 in Mississippi, and 4 in Alabama.

5.3 Industry Characteristics

The offshore oil and gas industry was projected to spend about $100 billion in 2000 on 

deepwater oil and gas fields, pipelines, drilling rigs, and production platforms around the world, 

 

17PHI is formerly known as Petroleum Helicopters, Inc. 

18Evergreen Helicopter’s main point of presence in the Gulf is in Galveston, Texas. However, the 

Company’s headquarters is located in McMinneville, Oregon. 
68

and those expenditures can only increase as the ultra-deepwater moves into full development. 

Typically, each oil and service company is basically on their own to provide spare parts and 

material requisition orders (MRO) for their assets in oil fields around the world, although there is 

some sharing of assets and resources (Anderson and Esser 2000).

Industry-wide supply chain transactions involving original equipment manufacturer spare parts 

are estimated to be a hefty $90 billion per year. Of that, $25 billion is spent on MRO

expendables. There are more than 27,000 suppliers of MRO and OEM (Original Equipment 

Manufacturer) parts to the oil industry, and 90 percent of parts are supplied by 2,000 of those 

companies – an unusually large number indicative of a fragmented supply chain network

(Anderson and Esser 2000).

Along the Gulf coast of the United States, there are many onshore facilities that support the 

offshore industry. Exploration and production in the Gulf is concentrated in three areas: 

Western, Central and Eastern Gulf regions. Located adjacent to these three regions, there are 

hundreds of contractors operating ports, maintenance and shipbuilding facilities, as well as crew 

bases, and other supporting industries such as pipe-making and pipe-laying.

Western: The Western Gulf of Mexico Planning Area extends from South Padre Island Texas 

to the Sabine River, on the Texas – Louisiana border (Figure 5.1). According to December 1999 

MMS estimates, the western Gulf area has approximately 421 million barrels of oil and 5.9 tcf of 

gas of remaining proved reserves (USDOI, MMS 2002c). The major onshore key ports and 

facilities are located near the Corpus Christi, Galveston, and Port Arthur areas.

Figure 5.1. Western Gulf Planning Area.
69

Central: The Central Gulf of Mexico Planning Area extends from the Sabine River to Baldwin 

County, Alabama (Figure 5.2). According to December 1999 MMS estimates, the central Gulf 

area has approximately 2,556 million barrels of oil and 17.6 trillion cubic feet (tcf) of natural gas 

of remaining proved reserves (USDOI, MMS 2002c). Major ports and facilities are located in 

Morgan City, Venice, Intercoastal City, Cameron and Fourchon, LA. Additional facilities are 

located near Biloxi, MS.

Eastern: The Eastern Gulf of Mexico Planning Area extends along the Gulf’s northeastern coast 

for some 700 miles, from Baldwin County, Alabama, southward to the Florida Keys. The area 

encompasses approximately 76 million acres, with water depths ranging from tens of feet to 

over 9,900 feet. Since the late 1980's, a limited amount of OCS activity has taken place in this 

planning area because of administrative deferrals and annual congressional moratoria. In 2000, 

MMS estimated that between 6.95 and 9.22 tcf of natural gas and 1.57 and 2.78 billion barrels 

of oil and condensate are contained in the Eastern Gulf of Mexico Planning Area (USDOI, MMS 

2002d).

Due to the environmental and military concerns, little activity has taken place among shore 

facilities in regard to infrastructure support in the Eastern Gulf. What activity is underway is 

supported, in part, from many of the Central Gulf on-shore support facilities, though a growing 

support industry has existed in Mobile Bay, Alabama for some time. In the past, Mobile Bay 

drilling activities have largely been supported by Central Gulf facilities, as the Mobile area has 

Figure 5.2. Central Gulf Planning Area.
70

minimal infrastructure to support offshore gas exploration and development. The coastal areas 

of Texas and Louisiana are home to specialized industries that support offshore oil and gas 

drilling in the Mobile Bay area. Contractors from these areas provided the majority of workers 

needed to drill and develop Coastal Alabama gas. If exploration expands into the Eastern Gulf 

region, this area will likely see a significant expansion.

With the expanding interest in deepwater activities, many onshore facilities have migrated 

somewhat to areas that have capabilities of handling deepwater vessels, which require more 

draft. Since fewer ports have such access, dredging operations at existing facilities or contractor 

expansion to areas that can handle such vessels has occurred. This has also led to heated 

competition between port facilities. Many support industries have multiple locations among the 

key port facilities. For instance, Bollinger Shipyards has locations in Texas City, Galveston, 

Calcasieu, Morgan City, Houma, Lockport, Fourchon, as well as other locations in the Central 

Gulf Region.

5.4 Regulations

General Support and Repair Facilities: Although repair and maintenance and other onshore 

support services are not economically regulated, they are subject to numerous environmental 

statutes and guidelines. Repair and maintenance – because it is a part of, and often referred to 

in conjunction with, the shipbuilding industry – is subject to the same regulations as discussed in 

Chapter 4, Section 4. This includes the Resource Conservation and Recovery Act, United 

States Code, Title 10, Section 7311, the Clean Air Act, the Clean Water Act, and the 

Comprehensive Environmental Response, Compensation, and Liability Act. 

Other regulations that affect the onshore support industries may include:19

Emergency Planning and Community Right-To-Know Act: The Superfund Amendments and 

Reauthorization Act (SARA) of 1986 created the Emergency Planning and Community Right-toKnow Act (EPCRA, also known as SARA Title III), a statute designed to improve community 

access to information about chemical hazards and to facilitate the development of chemical 

emergency response plans by State and local governments. EPCRA required the establishment 

of State emergency response commissions (SERCs), responsible for coordinating certain

emergency response activities and for appointing local emergency planning committees 

(LEPCs). EPCRA regulations establish four types of reporting obligations for facilities which 

store or manage specified chemicals:

• EPCRA §302 requires facilities to notify the SERC and LEPC of the presence of any 

extremely hazardous substance (the list of such substances is in 40 CFR Part 355) if 

it has such substance in excess of the substance's threshold planning quantity, and 

directs the facility to appoint an emergency response coordinator.

• EPCRA §304 requires the facility to notify the SERC and the LEPC in the event of a 

release equaling or exceeding the reportable quantity of a CERCLA hazardous 

substance or an EPCRA extremely hazardous substance.

 

19 The following list is taken from: This section is taken from: Office of Compliance, Profile of the 

Shipbuilding and Repair Industry (Washington D.C.: Office of Enforcement and Compliance Assurance, 

Environmental Protection Agency), 1997, p. 81-92.
71

• EPCRA §311 and §312 require a facility at which a hazardous chemical, as defined 

by the Occupational Safety and Health Act, is present in an amount exceeding a 

specified threshold to submit to the SERC, LEPC and local fire department material 

safety data sheets (MSDSs) or lists of MSDSs and hazardous chemical inventory 

forms (also known as Tier I and II forms). This information helps the local

government respond in the event of a spill or release of the chemical.

• EPCRA §313 requires manufacturing facilities included in SIC codes 20 through 39, 

which have ten or more employees, and which manufacture, process, or use

specified chemicals in amounts greater than threshold quantities, to submit an

annual toxic chemical release report. This report, known commonly as Form R, 

covers releases and transfers of toxic chemicals to various facilities and

environmental media, and allows EPA to compile the national Toxic Release

Inventory (TRI) database.

All information submitted pursuant to EPCRA regulations is publicly accessible, unless

protected by a trade secret claim.

Safe Drinking Water Act: The Safe Drinking Water Act (SDWA) mandates that EPA establish 

regulations to protect human health from contaminants in drinking water. The law authorizes 

EPA to develop national drinking water standards and to create a joint Federal-State system to 

ensure compliance with these standards. The SDWA also directs EPA to protect underground 

sources of drinking water through the control of underground injection of liquid wastes. EPA 

has developed primary and secondary drinking water standards under its SDWA authority. EPA 

and authorized States enforce the primary drinking water standards, which are contaminantspecific concentration limits that apply to certain public drinking water supplies. 

Toxic Substances Control Act: The Toxic Substances Control Act (TSCA) granted EPA

authority to create a regulatory framework to collect data on chemicals in order to evaluate, 

assess, mitigate, and control risks which may be posed by their manufacture, processing, and 

use. TSCA provides a variety of control methods to prevent chemicals from posing

unreasonable risk. 

TSCA standards may apply at any point during a chemical’s life cycle. Under TSCA §5, EPA 

has established an inventory of chemical substances. If a chemical is not already on the 

inventory, and has not been excluded by TSCA, a pre-manufacture notice (PMN) must be 

submitted to EPA prior to manufacture or import. The PMN must identify the chemical and 

provide available information on health and environmental effects. If available data are not 

sufficient to evaluate the chemicals effects, EPA can impose restrictions pending the

development of information on its health and environmental effects. EPA can also restrict 

significant new uses of chemicals based upon factors such as the projected volume and use of 

the chemical. Under TSCA §6, EPA can ban the manufacture or distribution in commerce, limit 

the use, require labeling, or place other restrictions on chemicals that pose unreasonable risks. 

Among the chemicals EPA regulates under §6 authority are asbestos, chlorofluorocarbons 

(CFCs), and polychlorinated biphenyls (PCBs).

Under TSCA §8, EPA requires the producers and importers of chemicals to report information 

on chemicals’ production, use, exposure, and risks. Companies producing and importing 

chemicals can be required to report unpublished health and safety studies on listed chemicals 
72

and to collect and record any allegations of adverse reactions or any information indicating that 

a substance may pose a significant risk to humans or the environment.

Heliports: Heliports are regulated by a number of different federal and state agencies. All flight 

operations, for instance, are regulated by the Federal Aviation Administration (FAA). Aircraft 

accidents are regulated by the National Transportation Safety Board (NTSB). Standards related 

to workplace health and safety are regulated by the federal Occupational Safety and Health Act 

(OSHA).

The FAA holds jurisdiction over most aspects of the air transportation business. This includes 

oversight of flight operations, personnel, aircraft, and ground facilities. Air transportation 

providers must obtain an Air Taxi Certification from the FAA, to transport personnel and

equipment to offshore regions. The FAA requires air transportation companies to file periodic 

reports associated with flight operations.

Most air transportation companies are also subject to certain regulations associated with the 

Communications Act of 1934 because of ownership and operation of radio and communications 

equipment used for flight operations.

5.5 Industry Trends and Outlook

General Support Facilities/Repair and Maintenance Yards: As noted earlier, offshore

support and transportation facilities are highly dependent upon drilling and production activities, 

which in turn, are highly dependent upon oil and gas commodity prices. In many ways, the 

supply and transport side of the offshore industry are one of the first to feel the sting of industry 

downturns. During periods of contraction, discretionary supply, repair, and maintenance

activities are the first to be cut to reduce E&P companies’ costs, thereby maintaining profitability.

Over the past 10 years, oil and gas commodity prices have been relatively low.20 Depressed 

prices and offshore activities have had a number of impacts on the support side of the industry. 

This includes a move towards diversification, concentration, and losses of qualified workers. 

Firms supporting shipbuilding and platform fabrication activities have been the most noticeable 

in terms of expanding operations into supply and support activities not only for the oil and gas 

industry, but for other industries as well. A number of general attributes associated with these 

facilities have led to their successful diversification. These characteristics include: general large 

geographic areas for work and storage; varied sources of unskilled and skilled labor (i.e., 

electricians, pipefitters, welders); and, access to supporting infrastructure (i.e., roads,

waterways, ports, communications). Many firms that provide support activities to the offshore 

industry have diversified into other areas both within and outside the oil and gas industry. 

The support activities that many shipbuilders and platform fabricators are conducting include 

dry-docking, inspections, maintenance and surveys of stacked rigs and equipment. Another 

new area includes work on production systems. While relatively low-dollar-per-task work, it is 

more stable than traditional fabrication work and can help keep important yards economically 

viable during downturns.

 

20One exception to this trend would be the significant natural gas price spike that occurred during the 

2000-2001 heating season. 
73

Another trend in the support industry has been in concentration. As noted above, in the past, 

several support activities were conducted by numerous contractors spread across the Gulf in 

different firms and different industries. Larger firms now, however, are diversifying into support 

work to diversify and smooth variation in revenues. These firms can be successful given the 

attributes discussed above, as well as their ability to bring some economies of scale to service 

provision. The merger and acquisition activity in the industry has also brought about a

significant number of changes and concentration in oil and gas E&P support.

As one industry observer recently noted: “trying to follow the merger and acquisition news in 

the U.S. shipbuilding industry these days is almost like playing the shell game. You don’t know 

where the little pea is going to wind up” (Snyder 2002). Litton Industries, Inc. – the parent of 

Ingalls Shipbuilding in Pascagoula, MS – completed its acquisition of Avondale Industries Inc., 

in the summer of 1999. Ingalls Shipbuilding is one of the Big Six defense oriented shipyards 

and its activities associated with the oil and gas industry have been of growing importance. The 

transaction was an all cash deal, valued at approximately $529 million. The newly created 

Litton Ship Systems organization will have combined revenues of approximately $1.8 billion in 

the shipbuilding and ship-modernization market, and with its 17,000 employees, will be capable 

of producing any class of non-nuclear ship for military and commercial customers (Aerotech 

News and Review 2002). These commercial customers include the oil and gas industry.

Previously, Newport News had made an earlier bid to acquire Avondale, but withdrew from its 

pursuit when Litton got involved. Litton had also made a separate offer to acquire Newport 

News, but backed off after Defense Secretary William Cohen publicly opposed the merger of 

Litton and Newport News, saying it would dilute competition in the U.S. Navy shipbuilding 

market. More recently, in April 2001, Northrop Grumman Corporation announced that it had 

completed the purchase of all tendered shares of Litton Industries Inc. common and Series B 

preferred stock, after receiving all required U.S. and international governmental and regulatory 

approvals (Northrup Gruman 2002).

The Big Six (or now Big Three) are united for lobbying purposes under the American

Shipbuilding Association banner. “Of course, the Big Six are not the only shipbuilders that have 

been doing the merger tango” (Snyder 2002). In the late 1990s new companies with old roots 

and familiar names have emerged in the commercial shipyard sector. Conrad Industries, First 

Wave/Newpark Shipbuilding, Friede Goldman International, and United States Marine Repair 

have all either been formed through mergers or grown through acquisitions. 

Offshore energy is an important driver of new construction at U.S. shipyards. Excluding inland 

barges, equipment for the offshore energy sector represented the largest percentage of 

deliveries by U.S. shipyards in 1998, according to Marine Log's shipbuilding database. Anchor 

handlers, offshore supply vessels, lift boats, and mobile offshore drilling units represented

roughly 36% of all the self-propelled vessels delivered in the U.S. Most of these vessels were 

built by facilities along the Gulf Coast (Snyder 2002).

Perhaps the visible and important impact of price volatility on support industry organization is 

associated with the flight of so many experienced personnel to industries that are less cyclical. 

When experienced workers leave the industry, it is very difficult to entice them back. These 

shortages have led to a greater emphasis on diversification among contractors, and often

results in mergers and acquisitions, leaving fewer contractors. While technological

developments have led to increased production with lower costs, qualified workers remain in 

short supply. The DOE found that one of the greatest risks to the success of offshore
74

development is the critical shortage of expertise in several key areas. Over the next decade, it 

reports, nearly half of the technology and business leaders in the ultra-deepwater area alone will 

retire (Office of Fossil Energy 2000). With fewer people entering the fields, colleges, 

universities and trade schools re-focus their efforts, leading to a further decline in employee and 

experience replacement.

Heliports: The helicopter and air transportation market in the Gulf is highly competitive. Most 

contracts are awarded through a competitive bidding process. Bids are typically evaluated on a 

number of considerations including price, safety, reliability, availability, and service (PHI, Inc. 

2001). As noted earlier, there are three major providers of helicopter services in the Gulf: PHI, 

Inc.; Air Logistics, Inc.; and Evergreen Helicopters, Inc. All three garner significant amounts of 

their business from the oil and gas industry. In addition, all three companies, to varying 

degrees, operate and/or maintain aircraft that are owned by E&P companies.

Most all of the providers of air transportation services in the Gulf are dependent upon the oil and 

gas industry. For instance, in its recent Annual Report, PHI notes that approximately 72 percent 

of 2001 operating revenue is attributable to helicopter support for the oil and gas industry. Air 

Logistics recently noted that approximately 97 percent of its revenues come from providing oil 

and gas air transportation services world wide – about 36 percent of all air transportation 

revenues were from the Gulf.21 For all of these companies, their air transportation services are 

not limited to the Gulf alone. All three provide services internationally in other global basins.

In addition to being concentrated within the oil and gas industry, many of these air transportation 

providers have revenues that are concentrated with one oil and gas company. For instance, 

Offshore Logistics noted that during 2000-2001, one customer accounted for 13 percent and 12 

percent of consolidated operating revenues (Air Logistics 2001a). PHI, Inc. noted that Shell Oil 

Company accounted for 15 percent of 2001 operating revenues (PHI, Inc. 2001).

There are a number of risks to air transportation service providers in the Gulf. These risks

include:

• Dependence on the oil and gas industry, including concentration of customers;

• Adverse weather conditions and seasonality;

• Political, economic, and regulatory uncertainty; and,

• Safety and insurance.

Most major air transportation providers in the Gulf have attempted to diversify over the years to 

balance their revenues. For instance, after the 1986 oil price decrease, Evergreen Helicopters 

turned its attention to spraying crops and other agricultural applications. Evergreen, as well as 

PHI, Inc. have also turned to emergency medical transportation as a means for revenue 

diversification. PHI, for instance, was one of the first to use Sikorsky S-76s for air transportation 

through Air Med affiliate, which provides air services to Acadian Ambulance in south Louisiana

(Oil Daily 1990). 

In addition to diversifying into other areas of air transportation services, one helicopter service 

provider has expanded into production activities of the oil and gas industry. Grasso Production 

Management (GPM), a wholly owned subsidiary of Air Logistics, is an offshore production

 

21This is based upon an estimate from the Company’s 10-K filing for 2001 before the Securities and 

Exchange Commission. No estimates were available for Evergreen, which is a privately held company. 
75

management company. GPM employees are assigned to over 200 platforms, serving

independent as well as major oil companies (Air Logistics 2001a). According to the company, 

GPM’s services include furnishing personnel, engineering, production operating services,

paramedic services, and the provision of boat and helicopter transportation between onshore 

bases and offshore platforms. The company’s investment in GPM was influenced by its belief 

that a restructuring in the U.S. oil and gas industry was taking place, creating opportunities to 

provide production management services to both independent and major oil and gas companies 

as they either grow, contract, or refocus their activities (Air Logistics 2001b).
77

6.0 WASTE MANAGEMENT FACILITIES

6.1 Introduction

The purpose of this chapter is to provide information regarding waste streams generated by oil 

and gas exploration and production activities on the OCS of the Gulf and methods used to 

manage them, both currently and prospectively. Capacity of the waste management

infrastructure is a particular focus. Capacity of a waste facility has two dimensions – short-term 

capacity and life-of-site capacity. In the short term, a waste facility can face limits to the volume 

of waste it accepts either from permit conditions or from physical limitations to the site, such as 

unloading bays, traffic conditions, or equipment capacity. Life-of-site capacity is also a limiting 

factor for disposal facilities. Limitations of storage space or service life make it necessary to 

consider what must happen after existing facilities have exhausted their capacity. For example, 

it may be difficult to replace facilities using older and arguably less protective technology. New 

permitting of some of the older technologies are either banned or burdened with additional 

requirements under environmental regulations that were not in place at the time the facilities 

were opened.

For OCS exploration and production (E&P) wastes that are returned to land for management, 

the infrastructure network needed to manage the spectrum of waste generated by OCS

exploration and production can be divided into three categories:

• Transfer facilities at ports, where the waste is transferred from supply boats to 

another transportation mode, either barge or truck, toward a final point of disposition;

• Special-purpose oilfield waste management facilities, which are dedicated to

handling particular types of oilfield waste; and,

• Generic waste management facilities, which receive waste from a broad spectrum of 

American industry, of which waste generated in the oilfield is only a small part.

For the first two categories, this chapter presents a comprehensive inventory of Gulf Coast 

waste management facilities and their capacities. Generic waste management facilities do not 

lend themselves to such an analysis for several reasons, one being that these facilities have 

unique permit terms that render physical capacity only a small factor in a site’s longevity. Solid 

waste landfills, likewise, receive only a small fraction of their total loading from OCS activities. 

These types of facilities will be addressed generically by means of discussion of typical waste 

management facilities, but are not included in the waste management facilities database

developed as a part of this project because; 1) no site by itself is important to the OCS waste 

management issue, 2) OCS waste is not important to any of these sites as a source of

business, and 3) difficulties related to predictability and identification.

Both the Gulf Coast OCS and the oil and gas waste management industry appear to be 

undergoing significant changes. New drilling technologies and policy decisions as well as 

higher energy prices should increase the level of OCS activity, and with it, the volumes of waste 

generated. The oilfield waste industry, having been mired in somewhat stagnant conditions for 

almost two decades, may develop new increments of capacity under stricter environmental 

permitting rules, such as zero discharge, than those in place when the existing infrastructure 

was developed. For this reason, this chapter includes information on new developments that 
78

may be important to long-term projections but do not form a part of the current waste

management infrastructure network.

6.2 Description and Typical Facilities

Types of Waste Generated: A number of different types of waste are generated as a result of 

offshore exploration and production activity. These include:

• Solids, such as drill cuttings, pipe scale, produced sand, and other solid sediments 

encountered during drilling, completion, and production phases. 

• Drilling muds, either oil-based, synthetic, or water-based. 

• Aqueous fluids having relatively little solids content, such as produced waters, waters 

separated from a drilling mud system, clear brine completion fluids, acids used in 

stimulation activities, and wash waters from drilling and production operations.

Although most of these are potentially dischargeable under the National Pollution 

Discharge Elimination System (NPDES) general permit, the possibility always exists 

that some amount of material will become contaminated beyond the limits of

treatment capabilities and will require disposal in a land-based facility. 

• Naturally Occurring Radioactive Materials (NORM), such as tank bottoms, pipe

scale, and other sediments that contain naturally high levels of radioactive materials. 

NORM occurs as a sludge and also as scale on used steel vessels and piping when 

equipment has been exposed to other NORM materials after very long periods of 

use.

• Industrial hazardous wastes, such as solvents and certain compounds with chemical 

characteristics that render them hazardous under Subtitle C of the Resource

Conservation and Recovery Act and thus not subject to the exemption applicable to 

wastes generated in the drilling, production, and exploration phases of oil and gas 

activities.22

• Nonhazardous industrial oily waste streams generated by machinery operations and 

maintenance, such as used compressor oils, diesel fuel, and lubricating oils, as well 

as pipeline testing and pigging fluids. Some operators and state regulators may 

choose to handle waste from drilling and production machinery as industrial wastes. 

Used oil generated by exploration and production operations may legally be mixed 

with produced oil, but refineries discourage the practice. These streams often

become commingled with wash water. They may be handled in drums or in bulk as 

part of a larger waste stream.

• Municipal solid waste generated by the industry’s personnel on offshore rigs,

platforms, tankers, and workboats.

 

22 40 CFR 261.4 (b)(5)
79

The different physical and chemical characteristics of these wastes make certain management 

methods preferable over others. In Section 6.3 – Industry Characteristics, we address how 

different waste management methods are used for different circumstances. 

Quantification of Wastes Generated: This chapter integrates much of the available

information on the quantities of wastes generated by OCS exploration and production activities 

into a comprehensive Gulf of Mexico waste generation model (OCSGEN). The spreadsheet 

model attached as Appendix III uses recent MMS assumptions about the number of wells, the 

required maintenance over their life, and the volume of hydrocarbon produced as inputs. At 

present, they are set as the average of the High and Low cases that have been used in recent 

MMS impact analysis. These inputs may be changed at any time in response to new leasing 

decisions, alternative resource estimates, or future energy economics. The inputs are multiplied 

by estimates of averages generation rates for each type of waste and each type of activity to 

arrive at estimates for total volumes generated and total volumes transported ashore by

planning area and for the Gulf Coast as a whole.

OCSGEN is a first step in integrating waste management decisions into considerations of

broader impacts. Further research that uses more detailed, special-purpose data collection 

could result in more accurate estimates of waste generation. With relatively little effort, for 

example, the total transportation impacts of an alternative discharge rule could be modeled and 

compared to existing rules. MMS has this type of analysis within relatively easy reach as a

result of other research efforts into resource valuation considering social costs and future 

platform requirements. 

Inventory: Based on an inventory conducted as part of the development of a GIS database for 

this project, 41 waste management facilities that service the oil and gas industry were recorded 

within the Gulf region; 25 in Louisiana, 11 in Texas, 3 in Mississippi, and 2 in Alabama (Table 

6.1).

6.3 Industry Characteristics

The U.S. EPA has established a hierarchy of waste management methods that it deems

preferentially protective of the environment. For those technologies applicable to oil and gas 

production waste, the following general waste management techniques are described in order of 

EPA’s preference: 

• Recycle/re-use: When usable components such as oil or drilling mud can be 

recovered from a waste this means that these components are not discarded and do 

not burden the environment with impacts from either manufacturing or disposal.

• Treatment/detoxification: When a waste cannot be recycled or re-used it can

sometimes be treated to remove or detoxify a particular constituent prior to disposal. 

Neutralization of pH or removal of sulfides are examples of technologies that are 

used with oil and gas wastes. 

• Thermal treatment/incineration: Wastes with organic content can be burned, 

resulting in a relatively small amount of residual ash that can be incorporated into a 

product or sent to disposal. This technology results in air emissions, but the

residuals are generally free of organic constituents. 
80

Table 6.1

Waste Management Facilities in Gulf which Support Offshore Oil and Gas Industry

Owner City State Class Primary Type

 Environmental Treatment Team Theodore AL Tr Other

 Waste Mgmt. Chastang Landfill Chastang AL Di LFill

 BFI Ridgeland MS Di LFill

 Waste Mgmt. McNeil MS Di LFill

Waste Mgmt. Grove Landfill Pass Christian MS Di LFill

ETT (Env Treatment Team Morgan City LA Tr Unknown

Habetz Oilfield Saltwater Disposal Crowley LA Di SD

Hallar Enterprises Inc. Pierre Part LA Di Inj

Houma Saltwater Disp Co. Houma LA Di Inj

J&R Systems Inc. Rayne LA Di Inj

 L & S Service Corp. Oil City LA Di Inj

Louisiana Tank Inc. Lake Charles LA Di Inj

Miller SWD Gueydan LA Di Well

 NES Nonhaz Injection Disp Facility Winnie LA Di Inj

 NES Now Transfer Facililty #2 Port Fourchon LA Tr SD

NES Now Transfer Facility Venice LA Tr Not Listed

NES Transfer Facility Morgan City LA Tr SD

NES Transfer Station Cameron LA Tr SD

NES Transfer Station Intracoastal City LA Tr SD

NES Transfr Facility #1 Port Fourchen LA Tr SD

Oilfield Brine Disposal Abbeville LA Di Well

Philip Services Jeanerette LA Di Inj

Pool Company Sarepta LA Di Inj

Saline Injection Systems Company Egan LA Di Inj

SWD Inc. Iowa LA Di Well

SWD Inc. Lacassine LA Di Inj

US Liquids Elm Grove LA Di LFarm

US Liquids Jennings LA Di 3 Inj and Lfarm

Waste Mgmt. Kelvin Landfill Kelvin LA Di SD

Waste Mgmt. Woodside Landfill Baton Rouge LA Di SD

 Burns Saltwater Disposal Victoria TX Di SD

Eco Mud Disposal Alice TX Di LFill

Key Energy Services Brookeland TX Di SD

NES Port Arthur TX Di SD

NES (Newpark Env Services) Ingleside TX Tr SD

NES Norm Processing & Inj Facility Winnie TX Di Inj

NES Now Injection Facility Hamshire TX Di SD

Norm Services Group TX Di Inj

Smith Disposal Facility TX Di LFill

Trinity Anahuac TX Di SD

Waste Facilities Inc. Premont TX Di LFarm

NOTE:

Class Di = Direct

Tr = Transfer

Primary Type

LFill = Landfill; SD = Saltwater Disposal; Inj = Injection; LFarm = Land farm

Source: RPC, 2001; The Louis Berger Group, Inc. 2001
81

• Subsurface land disposal: This technology places waste below usable drinking 

water resources and is viewed as superior to land filling due to the low potential for 

waste migration. Injection wells and salt cavern disposal are examples of this type of 

technology. 

• Surface land disposal/treatment: This type of technology involves placement of 

wastes into a landfill or onto a land farm. Although well-designed and constructed 

landfills minimize the potential for waste migration, generators remain concerned 

about migration of contaminants into water resources and avoid it whenever

practical. EPA classifies surface land disposal as the least desirable disposal

method (USEPA 1995).

Several waste management methods are used to handle the spectrum of wastes generated by 

OCS activity, and most types of wastes lend themselves to more than one method of

management. Choice of method will depend on the following factors:

• An operator’s perception of long-term liability for the waste;

• Physical characteristics of the wastes, such as solids content or oil content;

• Processing or disposal cost;

• Cost of transportation from the point of generation to the waste management facility; 

and,

• Preexisting business relationships with a waste management facility.

Each of these options has a different set of environmental impacts, regulatory constraints, costs, 

and capacity limitations. For example, industrial nonhazardous oily waste streams are

managed at facilities that manage oily wastes for a broad range of industries. The same is true 

for municipal solid waste and hazardous waste. Most NORM and nonhazardous oilfield wastes 

(NOW) are only handled by specialized oilfield waste facilities in the Gulf Coast area, although 

there are exceptions. The most common oilfield waste management methods are provided in 

the rest of this section. 

Discharge into the Sea: Wastes discharged into the sea must be virtually free of hydrocarbons 

and any other chemicals that would be harmful to marine life. Produced water, by far the most 

abundant oil and gas waste stream, can meet this definition after appropriate treatment steps. 

Water-based drilling muds that are: 1) made from clean barite, 2) without certain chemical 

additives, and 3) have not encountered hydrocarbons are also dischargeable into the sea under 

emerging regulations (USEPA 1999). Finally, domestic and sanitary sewage from rig

employees, after certain pretreatment steps, may also be discharged into the sea under most 

circumstances (USEPA 1996).

This practice is prevalent in offshore production and is regulated under 40 CFR, Part 435, 

Subpart A, which addresses application of the National Pollution Discharge Elimination System 

(NPDES) for Gulf Coast discharges in the Western and Central Planning Areas. The principal 

concern is that oil is properly separated from the saltwater before discharge – often requiring 
82

one or more pretreatment steps to achieve the limitations of total organic compounds (TOC) set 

out in the General NPDES permit for EPA’s Region 4.23

Costs: Discharge into the sea clearly has an overwhelming cost advantage because

transportation costs are avoided. Cost for simple, continuous streams of produced water is 

virtually nothing, while setup to treat the most difficult intermittent stream might cost over a 

million dollars. Cost per barrel depends on the nature of the waste stream and life span of the 

wells served by the installation.

Siting Requirements and Environmental Issues: The Federal regulations set forth in the NPDES 

permit for the eastern Gulf apply in areas with water depths in excess of 200 meters. The 

NPDES permit prohibits discharges within 1,000 meters of an environmentally sensitive area –

which really only comprise less than 1 percent of the OCS. The most prevalent environmentally 

sensitive areas are the benthic (bottom-dwelling) communities found around small areas where 

methane vents into the sea and provides a food source and unique habitat for the specialized 

organisms that have developed around them.

Areas closer to shore generally have greater environmental sensitivity due to more prevalent 

soft substrates and greater nutrient loading. In areas along the western Florida shelf, seagrass 

beds are a dominant feature of the sea floor. In addition, commercial and recreational fishing 

grounds are present.

Although EPA has amassed considerable data indicating the discharge restrictions are

protective of the environment, many members of the public disagree and question the industry’s 

willingness to comply, given the abuses possible under the self-reporting rules in NPDES. 

Future OCS operations may in some cases occur closer to more environmentally sensitive 

areas than historical activities, prompting renewed scrutiny of the impacts of discharges. In any 

event, the question of discharge impacts is sure to be a prominent issue in the public eye for 

years to come. 

Outlook and Capacity Issues: EPA has reserved the right to monitor the effectiveness of these 

restrictions and to change them later if they prove not to be fully protective. For example, a 

well-publicized violation or accident with significant impacts could cause modifications to EPA 

policy on discharges. Any prominent spill, or failure of a treatment system to perform properly, 

could prompt a call for more restrictive discharge rules that could include an outright ban in 

some situations. Future lease blocks closer to Florida, if any, could face different requirements 

or even be subject to a zero-discharge policy. 

For planning purposes, it must be assumed that there is at least a possibility that discharges will 

be further limited in the future. If this were to be the case, both costs and logistics would

indicate that on-platform subsurface injection facilities, perhaps complemented by salt dome 

disposal facilities for drilling muds (both discussed below), would accommodate the

overwhelming volume of offshore waste. The prospect of many millions of barrels per year 

coming ashore, as indicated by OSCGEN, implies far more costs, transportation equipment and 

shipping traffic than would be tolerated by any stakeholder, given the relative ease of

subsurface injection.

 

23 Federal Register Vol. 63, No 200, Oct 16, 1998
83

Subsurface Injection:

24

 Subsurface injection is the management method used for more than 

90% of the 16 billion barrels of saltwater produced by onshore oil and gas production each year 

in the U.S. (Figure 6.1) (ICF 2000). An injection well can best be envisioned as a producing well 

operating in reverse, with very similar drilling and completion procedures. (Depleted producing 

wells are, in fact sometimes converted to injection wells.) Subsurface injection of aqueous fluids 

into a porous rock formation is the oldest and most established technology for disposal of 

produced waters onshore or when discharge is not allowed offshore. 

Class II Injection Wells for

Disposal of Oilfield Waste

About 70 percent of the volumes injected in the U.S. serve the dual purpose of waterflooding the 

field, which is essentially pushing residual hydrocarbons to selected wells in a secondary oil 

recovery project (ICF 2000). Less often, the injection zone is either depleted or otherwise not 

productive of hydrocarbons. Underground injection is most suitable for relatively solids-free 

liquids – fluids are often filtered before injection because many injection formations cannot 

tolerate significant levels of solids without plugging. In these cases, the filtrate and sometimes 

 

24 We use the term “subsurface injection” of waste in its more traditional sense of meaning injection 

into a porous rock formation as opposed to the newer waste management method of salt cavern disposal, 

which is also technically subsurface injection but significantly different from this method both technically 

and legally.

Figure 6.1. Injection Wells for Oilfield Waste.
84

the filters themselves then become a solid-form waste stream that must be managed.25 Some 

formations, on the other hand, are sufficiently porous and tolerant of solids so as to present a 

viable method of disposing of sludges. The most prominent example of the latter is the 

Newpark facility located near Fannett, Texas in Jefferson County. 

The Newpark facility is the most important NOW facility for the offshore industry, having 

received some 5,000,000 barrels of offshore waste (generated in state-waters) in 1998, 

constituting about 75 percent of the total offshore NOW or NORM streams shipped ashore. 

(Volumetrically, the NORM components are miniscule).26

Costs: The cost of an underground injection system varies greatly with the scale and the 

difficulty associated with the fluid being managed. A high-volume pipeline-gathered injection 

system can be operated between $.05 and $.10 per barrel. In contrast, land-based commercial 

disposal wells, which serve wells that do not have sufficient volumes to justify a captive pipeline 

system typically charge $.25 to $.40 per barrel in the Gulf Coast region, with transportation 

usually adding two or three times that amount.

A slurry injection facility, such as the one at the Newpark facility, has all the requirements of a 

liquids injection facility, and additional equipment to store, pump, and grind sludge to the 

uniform required particle size. Disposal prices at slurry injection facilities typically range from 

$8.00 to $14.00 per barrel at the wellhead. The cost for NORM waste disposal is relatively high 

($100 to $200 per barrel) due to the significant handling restrictions necessary to manage this 

type of waste. In addition, the material is often managed in drums, a practice that by itself 

commands a significant premium over wastes handled in bulk.

Siting Requirements and Environmental Issues: All facilities employing a form of underground 

injection rely on the availability of a suitable underground formation or structure for

emplacement of wastes. Most areas along the Gulf Coast have at least one subsurface

geologic formation suitable for underground injection. To be suitable for injection, a geologic 

formation must be of sufficient thickness and permeability to accept reasonable amounts of fluid 

as well as the residual solids that escape filtration. The injection zone must also be situated 

with sufficiently impermeable formations above and below it to isolate the injected material from 

usable groundwater and other resources. The most porous and permeable formations can be 

extremely tolerant of solid particles--to the extent that they can be used for the disposal of 

slurried solids if the particles are uniformly small enough to pass through formation pore spaces.

Subsurface injection wells are regulated as Class II injection wells under the EPA’s underground 

injection control program authorized by the Safe Drinking Water Act and pursuant to regulations 

set forth in 40 CFR Part 144 that were first promulgated in 1983. EPA directly regulates 

injection wells in Federal waters and delegates authority for the state programs to the Texas 

Railroad Commission, the Louisiana Department of Natural Resources, Mississippi Oil and Gas 

Board, and the Alabama Department of Environmental Management. The regulatory program is 

 

25A similar technology, annular injection, is used at the point of generation and sometimes used 

onshore in a commercial mode, but has generally been less accepted due to concerns about the fate of 

the waste once injected. Some newer approaches involve extensive characterization of the receiving 

formation and seem to hold the promise of broader acceptance, especially for offshore applications.

26 Newpark Resources Form 10-K, 1999, and telephone contact with Chief Technical Officer,

December 1, 2000 by Steve Mobley, RPC.
85

mature and the technology has an established record of good performance, despite decades of 

operations under considerably less protective regulation than those that exist today. 

Disamenities associated with this method are the visual and noise issues one might encounter 

at a producing well with a relatively large amount of tankage and pump noise. If the products 

received are sour – containing sulfurous compounds - odor problems can be significant to a 

larger area; otherwise, they are rarely an issue beyond the immediate proximity of the site. 

Facilities that receive waste via truck have the potential for large traffic impacts on smaller

roads. Injection wells are sometimes perceived by regulators not familiar with them to present a 

threat to groundwater resources, although the historical record of waste migrating out of the 

injection zone to a higher freshwater formation is very sparse. For the most part, regulators in 

energy-producing regions, who have a long experience with injection wells, are comfortable that 

the technology is protective of groundwater resources.

Outlook and Capacity Issues: Waste is isolated in the injection zone from zones above it by 

overlying formations that form a seal, although there are typically no well-defined edges to the 

formation that would serve as the sides of what might incorrectly be envisioned as a container. 

For this reason, injection zones usually do not have capacity limits that can be meaningfully 

measured against the relatively finite amount of waste that may be generated within the local 

area. 

Subsurface injection facilities have two limitations. Any given injection zone will accept fluid at a 

certain rate, depending on porosity, permeability, and thickness of the formation. This tends to 

govern the maximum amount of waste that may be disposed of daily in a given well. Second, 

any given injection well is subject to irreparable failure of the casing or the cement around the 

casing as well as to “skin damage” to the formation at its interface with the wellbore. With 

proper design and operation, most wells can be expected to last 15 or 20 years. When a well 

fails, redrilling within a few hundred feet is often an option, although the oil and gas production 

that led to the requirement of a well in the first place may well play out before then. Life-of-site 

capacity at a given location, then, is usually not an issue as much as how long saltwater from 

nearby wells will be produced.

Long term, capacity to install subsurface injection facilities onshore is itself not scarce and 

oilfield waste injection well permits do not generally attract much public opposition. With the 

volume of produced water frequently exceeding the volume of oil a well produces by tenfold or 

more, the main limitation to widespread use of land-based subsurface injection facilities is the 

space at docks and the traffic in and out of ports. 

Salt Cavern Disposal: Almost anything that can physically be pumped downhole can be 

disposed of in a salt cavern. Salt cavern disposal has an advantage over subsurface injection 

as disposal of solids-laden sludges may be difficult to get into the rock formation. Although salt 

caverns can easily accept liquid, cost factors dictate that liquids will generally be disposed of 

through subsurface injection instead of salt cavern disposal. The reason is that salt caverns 

require an injection well for disposal of brine displaced from the salt cavern as waste is injected. 

As such, salt dome disposal creates a barrel-for-barrel requirement for injection well disposal. 

Thus, no fluids that can easily be managed by underground injection would be disposed of in 

salt caverns by choice.

Muds and solids that have been slurried can be pumped into synthetic voids formed within salt 

domes for the purposes of storage (Figure 6.2). These caverns are drilled and completed using 
86

solution-mining techniques and are used for storage of natural gas, crude oil, and other

hydrocarbons. To create the cavern, a well must be drilled into the salt dome. Fresh water is 

then pumped into the salt dome where it becomes saturated with salt. Saturated saltwater is 

circulated out of the dome through the annulus of the same well, which then must be disposed 

of through a subsurface injection well operation of the type described in above. Before waste is 

introduced, the completed cavern then resembles a giant salt-sided jug of brine. Injection wells 

are an integral part of a salt cavern disposal operation, because every barrel of saltwater

displaced must be disposed. Waste materials are then pumped into the cavern, displacing an 

equal volume of saltwater, which is injected in the disposal well operation. Temporary salt 

cavern storage of natural gas, natural gas liquids, and petroleum is well established in the U.S. 

in over 1,000 caverns, although their use for permanent disposal is a newer development.

Figure 6.2. Salt Cavern Waste Disposal.

Costs: One commercial salt cavern, operated by Trinity Field Services, has recently opened 

near Hamshire, Texas on the Trinity River. It presently receives waste only by truck, although 

management expects a barge mooring to be permitted within a year. Trinity Field Services 

publicizes prices of $8-15.00 per barrel, with discounts undoubtedly available for large volumes. 

Commercial salt caverns in other parts of Texas charge from $5 to $15 per barrel (bbl) for NOW, 

with surcharges applicable if the material must be blended into a pumpable state. This

Waste

Salt Cavern

Salt Dome

Formation

Final Casing

(Cemented)

Displaced Brine

Incoming Waste

Surface Casing

(Cemented)

Overlying

Formations

Annulus

Tubing

Salt Cavern Waste Disposal
87

technology has an advantage over typical subsurface injection in that the size of the solids 

pumped downhole is not an issue and it avoids the need to grind solids to a uniform particle 

size. NORM prices at Lotus, L.L.C. (a commercial salt dome in Andrews County, Texas) are 

approximately $150/bbl, plus approximately $5 bbl freight from Corpus Christi.

Siting Requirements and Environmental Issues: These facilities are only possible in parts of the 

country where salt deposits are found, in either bedded or domal formations. The Gulf Coast 

region, both onshore and offshore, has an abundance of salt caverns, many with barge access. 

As discussed in Chapter 10, many Gulf Coast salt domes are already in service for hydrocarbon 

storage. Salt caverns otherwise introduce no particular siting criteria except the need to 

maintain a sensible buffer from residential and commercial areas for reasons associated with 

odors and equipment noise. 

Like subsurface injection operations, salt cavern disposal facilities have minimal permanent 

impacts on the surface. Land is required for a wellhead, truck unloading, a small office, 

blending equipment, and tankage for short-term storage. The recently opened Trinity facility 

near Liberty, Texas occupies 40 acres but actually uses considerably less land than that.

Outlook and Capacity Issues: With the addition of Trinity Field Services to the market in 2001, 

the OCS market has its first salt dome disposal operation in a competitive location, with 6.2 

million barrels of space available initially -- enough to take eight to ten year’s worth of OCS 

liquids and sludges at current generation rates and a potential of several times that amount with 

additional solution mining. Salt domes are well-known and well-documented geological

structures, and others could be placed into service as demand dictates. Salt caverns are a finite 

resource, but nevertheless have the potential to take decades’ worth of OCS offsite NOW

generation.

Land Application: Drilling muds, produced sand, and other fine solids are candidates for land 

application, often called landfarming. Muds and other solids are spread on land and mixed with 

earth to be incorporated into the soil, or deposited into dedicated pits. Muds with no

hydrocarbons and low chloride content can sometimes be beneficially applied to pasture land, 

although the practice is increasingly avoided. In a pit system, hydrocarbon levels in the wastes 

are reduced using bioremediation techniques. Once hydrocarbon levels have been reduced to 

acceptable levels, the material can be used for landfill cover or road building material, an 

application in which the oil’s plasticity characteristics and water-resistivity are desirable. 

Alternatively, the whole cell can be closed in place as a monofill, which is essentially a specialpurpose landfill with only one waste stream.

Costs: Costs for disposal of NOW at landfarms range from $8.00 to $16.00 per barrel with the 

higher costs associated with higher liquid levels. 

Siting Requirements and Environmental Issues: Modern landfarm siting criteria are similar in 

many respects to landfill siting criteria, although less stringent in some respects simply because 

landfarms are by any measure much smaller operations than landfills. These criteria include:

• Sufficiently far from residences that odors and equipment noise are not an issue;

• Served by roads with gross vehicle weight rating of 80,000 pounds;

• Out of wetlands or 100-year floodplain;
88

• Pits are sometimes lined with an oil-resistant material such as high-density 

polyethylene plastic;

• If objective is to produce construction material from oil-based mud, pits should be 

sized to allow for 3-in high windrows and sufficient residence time to bioremediate 

the material down to a suitable hydrocarbon level (approximately 500 mg kg-1 TPH); 

and,

• If the treated waste is to be closed in place, keeping the areal extent of the pit as 

small as possible is a more important criteria.

Landfarming regulations in the Gulf Coast states depend on site-specific permits except for onsite disposal of onshore drilling waste. Landfarming carries a risk of long-term liability from 

either leakage of the monofill or liability from use of the recycled material. While any method 

has its risks, landfarming is perceived as riskier than either of the two injection methods by 

many operators and is avoided by many operators, and prohibited by still others. 

Outlook and Capacity Issues: Landfarm capacity and fill rates are difficult to estimate because 

they are typically small operations and because capacity is limited not only by physical size, but 

by toxic constituent loading. These facilities typically have permits that limit the total amount of 

toxic metals that can be applied per acre of land. Wastes with relatively high levels of toxic 

metals would cause a landfarm to reach its maximum metals loading much faster than relatively 

clean wastes. The facilities are available to accept offshore waste but actually accept very little 

because other methods are preferred by the operators and have stronger commercial and

logistical links to the offshore community. 

The use of landfarming of OCS waste is likely to decline further, particularly with greater 

availability of injection methods for wastes containing solids. Future regulatory efforts are likely 

to discourage the practice by adding requirements that damage the economics if not by an 

outright ban on future permits.

Landfilling: Workers on a rig or production platform generate the same types of waste as any 

other consumer in industrial society, and are therefore responsible for their fair share of

municipal solid waste (MSW). A large volume of industry-specific trash and industrial junk also 

makes its way to a landfill. 

A modern landfill is an engineered facility with protective liners and caps to isolate the waste 

from the larger environment (Figure 6.3). MSW is placed in an excavated cell, usually lined with 

high-density polyethylene to prevent leakage into the groundwater. MSW must be covered daily 

to control odors, birds, and vermin brought about by rotting food wastes.

Cuttings, muds or watery waste streams can be treated by mixing with a stabilizing agent such 

as cement kiln dust, lime, or often even a simple bulking agent such as sawdust or waste from 

papermaking processes. These materials will be introduced in a mixing vessel at the landfill 

and stirred with a track hoe until it has a desired consistency. Depending on the solids content 

of the original waste stream as well as the bulking agent, the growth in volume will vary; a cubic 

yard of fresh water could become two cubic yards of landfillable waste.27 Thus, an incoming 

cubic yard (approximately five barrels) of waste will occupy the landfill space of as much as four 

gate yards of MSW, which will be compacted in the landfill to half of its volume at the gate. 

 

27 5 bbls = 1 cubic yard. 2 cu. yds of MSW in place = 4 cu. yds of MSW at the gate.
89

This, along with the considerable treatment cost, argues for a much higher price for these 

streams than their incoming volumes would initially suggest. In other circumstances, described 

below, such streams may be attractive to a landfill operator as cover material.

A landfill must apply cover material of earth or some kind of non-putrescible material to the 

working face of the MSW daily. Drilling muds and wastewater streams that have been solidified 

may often serve as daily cover. Use of this type of material often improves a site’s soil balance, 

meaning the volume of soil required over the life of the landfill for its construction and operation 

will be less than if these materials were not available and other soils had to be hauled in at a 

cost. Up to a point, the materials consume no airspace since they are merely displacing soils 

that would be used for cover in any event. For this reason, landfills will often accept these 

materials at a reduced price, or even at no charge. Once a site has its daily cover requirements 

being met from revenue-positive gate receipts, its management would look quite differently at 

incremental volumes of such materials.

Costs: Landfill prices in the Gulf Coast region range from approximately $18.00 to $35.00 per 

ton for MSW - toward the low end of U.S. landfill prices.28 For NOW sludges, the range will 

 

28 Source: SWANA tipping fee survey

Plastic Liner

Compacted Clay

Leachate

Collection

Pipe

Soil

Layer

Geo-Textile Mat

Soil Layer

Old Cells

Holding

Pond

Municipal Landfill Oilfield Waste Disposal

Vegetated Cover

Leachate

(Arrows)

Vegetated Berm

Figure 6.3. Municipal Landfill Oilfield Waste Disposal.
90

depend greatly on the processing cost and the volume increase associated with adding

stabilization agents. Generally speaking, the range will be between $8.00 and $16.00 per barrel. 

Siting Requirements and Environmental Issues: Landfill siting criteria are at once exacting but 

vague. Nearly every landfill siting application results in an evidentiary hearing or is otherwise 

the subject of intense debate. The level of impacts that sites will have on adjacent land users is 

hotly debated by both applicant and intervening neighbors. Nevertheless, there are certain 

qualitative factors that describe the spirit, if not the letter, of what a successful application for a 

new landfill must contain. A new landfill should have the following characteristics:

• Not in the 100-year floodplain;

• Away from population centers;

• More than six miles from an airport (for landfills that receive putrescible waste);29

• Accessible by public roads built to withstand maximum legal truckloads with

significant excess capacity;

• Geologically simple and well-understood subsurface stratigraphy characterized by an 

absence of faulting, fracturing or folding;

• Groundwater deeper than maximum depth of excavation;

• Large enough tract of land for minimum of 20-year site life at expected opening fill 

rates (usually a minimum of 250 acres); and

• Established or expected use of neighboring land is industrial.

Environmental issues raised by landfills ultimately come down to: 1) potential threats to local 

groundwater, 2) impacts on local traffic, and 3) aesthetic considerations associated with truck 

traffic, nuisance odors, equipment noise, visual impairment of the landscape, and blown trash. 

All of these issues are generally confined to a very small area relative to the trade area of the 

modern landfill, which is typically at least a fifty-mile radius. If a landfill is properly sited, 

engineered, and operated, these impacts are minimized. Examples exist where quality

residential development has developed concurrently and harmoniously with nearby landfills.

Outlook and Capacity Issues: MSW disposal from OCS activities currently imposes only a small 

incremental load on the landfills examined in this study—for example, probably no more than 5 

percent of total receipts by all the landfills serving south Louisiana. Growth in these volumes 

can be expected to increase with increased OCS drilling and production activity although not 

strictly in a linear manner since the average number of workers per rig is declining. Recycling, 

seen in many applications as a replacement for landfills, should not be expected to have a 

significant impact on future landfill requirements from this sector. In work environments more 

amenable to recycling, where lack of time and space do not make for such a difficult

environment for source separation, recycling causes at best a modest reduction in landfill 

volumes. The conservative assumption, from the MMS planning standpoint, is that it will 

continue to be a small factor in the reduction of trash generated by OCS activity. Assuming a 

landfill: 1) presently had OCS waste constituting 5% of its waste stream, 2) the remaining life of 

a landfill was 20 years at current fill rates, and 3) OCS waste doubled but the rest of the 

incoming waste stream remained flat, then the OCS activities would cause the landfill to be 

 

29 This standard is for landfills that receive putrescible waste and can be relaxed with Federal Aviation 

Administration consent.
91

closed at the end of 19 years as a result of the OCS contribution increase. With no waste 

received from OCS activities at all, the landfill would close in 21 years.

Economics of stabilization and the relatively high value of MSW airspace compared to the costs 

of subsurface injection or salt cavern disposal generally make landfills a poor choice where 

drilling and production sludges and liquids are concerned. Landfills seem to receive drilling and 

production waste from OCS activities in unusual circumstances: 1) when landfills need cover 

material and will negotiate prices, 2) when other options present some kind of schedule

problems, and 3) when the physical form of the material make it a better choice. Some landfills 

will have a limited appetite for some solids originated from drilling and production activities, but 

for the most part it is not likely that landfills will gain a larger share of this market – thus limiting 

the impact on airspace life. 

Separation and Reclamation of Drilling and Completion Fluids: Drilling and completion 

fluids with a high value often justify considerable effort to reclaim and store them for a future 

use. Some drilling and completion fluids used offshore are very expensive either because of 

their petroleum-product content or because of their use of expensive clear brines such as

calcium bromide and zinc bromide. At times, these fluids can be cleaned up through

centrifugation in the field. At other times, they will be returned to the fluids company’s supply 

base, where separation equipment is used to return the fluid to a useable condition.

Costs: Reclaiming a barrel of fluid with a market value of $300 or more can understandably 

justify a large budget. The fluids service companies usually maintain title to the fluid as well as 

responsibility for disposal. Thus, reclaiming avoids a disposal charge but more important,

provides material to be used in another sale. Costs vary widely with circumstances and no 

representative figures have been found. Even at the high end of transportation and disposal 

charges discussed elsewhere, the economics of reclamation would be compelling.

Siting Requirements and Environmental Issues: These operations will typically occur on the 

fluids service company’s yard. The tankage and separations equipment used offshore are 

available on the service yard and no permits or additional authorizations are needed.

Reclamation operations generate sludge, which enters into the oilfield waste management

system just as any other sludge would. Depending on the filtration system used, filter media 

may be incorporated into the sludge or may be handled separately as relatively dry trash. Apart 

from these wastes, the reclamation operations present no impacts that are not inherent to the 

fluids themselves. If the fluids are carefully managed in both spent and ready-to-use forms, 

then the environmental impacts will be minimal. The value of the fluid in all stages of its uses 

argues that it will be conserved and reused whenever economically possible.

Outlook and Capacity Issues: Although reclamation is at the top of the RCRA hierarchy and has 

compelling economics in many cases, the economics of recovering fluid will get better only to 

the extent that the oil component in an oil-based drilling system, or the cost of clear brines, 

becomes more valuable. Capacity to reclaim is not limited in any sense other than in the very 

short term, when separation equipment to accomplish the processing may be short. This 

activity will only expand or contract directly with the number of barrels being used in the market 

at any given time.
92

Separation and Recycling of Industrial Wastes: Certain industrial wastes generated in the 

course of oil and gas development do not fall under an oil field waste exemption under RCRA 

Subtitle C. If they are not uniquely oilfield wastes, then the oil and gas waste exemption does 

not apply. Examples of such streams are lubricating oils for drilling machinery, oil filters, oilbased paint solvents, and parts degreasers. These activities are characteristic of painting metal 

and maintaining machinery, and are not unique to the oilfield. Generation of hazardous wastes 

has declined markedly in recent years as more environmentally friendly products have replaced 

them and the use of hazardous materials has been minimized in other ways. 

Costs: Table 6.2 presents a range of disposal costs for the different industrial wastes that fall 

into this category.

Table 6.2

Disposal Costs for Various Industrial Wastes

Waste Type Disposal Price Range

Industrial organic hazardous wastes $75 to $150 /gal

Inorganic liquid hazardous wastes $50 to $125 /gal

Oil filters $8 to $15 per 55 gallon drum

Used oil $ 0 to $0.15 per gallon

Oily wastewater $0.10 to $0.25 per gallon

Source: RPC, 2001

6.4 Regulations

Federal regulations govern what may be discharged in Gulf waters and establish different 

standards in different parts of the Gulf Coast. Table 6.3 summarizes Federal rules presently in 

place. Wastes that cannot be discharged or injected offshore must be brought to shore.

Transportation, packaging, and unloading of the waste at port are governed by U.S. DOT

regulations while the Coast Guard regulates vessel fitness. Once on the dock, transportation 

and packaging is subject to an overlay of U.S. DOT and state law. State regulations governing 

reporting and manifesting requirements may vary somewhat, but Federal law has for the most 

part preempted the field of transportation waste regulation. Dockside facilities that serve as 

transfer points from water to land modes of transportation are regulated by both Coast Guard 

and state regulations covering the management of oilfield wastes. Once at a waste

management facility, regulation regarding storage, processing, and disposal varies depending 

on the type of waste. Most would fall under the oil and gas waste exemption of RCRA Subtitle C 

and would be subject only to state regulations regarding the disposal of oilfield wastes. A minute 

volume of the waste would be subject to federal regulation as hazardous waste under RCRA 

Subtitle C. 
93

Table 6.3

Summary of Federal Rules Governing OCS Discharges and Injections

MMS 

Planning 

Region Rules Key Features

Western 63 FR 58722

NPDES General

Permit Rules

General permit restricting discharges to 29 mg/l monthly 

average and 49 mg/l maximum daily total oil and grease

Territorial 

Seas of

Louisiana

62 FR 59687

NPDES General

Permit Rules

General permit restricts discharges to 29 mg/l monthly and 

49 mg/l maximum daily total oil and grease. Requires 

monitoring for benzene, thallium, phenol, and lead. No 

free oil, cuttings or drilling fluids.

Central 63 FR 55717

NPDES

General permit for >200 meters of water depth restricting 

discharges to 29 mg/l monthly and 49 mg/l maximum daily 

total oil and grease

Eastern 63 FR 55717

NPDES

General permit for > 200 meters of water depth restricting 

discharges to 29 mg/l monthly average and 49 mg/l

maximum daily total oil and grease 

All of the above citations contain rules restricting discharge of domestic and sanitary sewage 

(including standards) and prohibiting discharge of trash in each of the MMS planning regions. 

Facilities located offshore of EPA Region 6 (and some in Regions 9 and 10) are subject to a 

general Clean Water Act permit that covers all facilities in certain geographic locations.

Offshore exploration and production facilities in Regions 4, 9 and 10 are also permitted

individually in some cases. EPA Regions 6 and 9 have a Memorandum of Agreement with 

MMS, whereby MMS agrees to conduct Clean Water Act preliminary inspections for EPA.

All CWA § 308, 402, 

403

Discharge rate limitations and monitoring; toxicity

limitations; minimize discharge of surfactants, dispersants 

and detergents; no rubbish, trash, or refuse, and no

discharge in areas of biological concern

All 40 CFR 144 Underground injection control program rules

State laws governing hazardous wastes are allowed to be more restrictive than federal law, but 

no material differences exist between state and federal law in Texas, Louisiana, Mississippi, or 

Alabama. For the most part, the wastes generated by oilfield activities, called nonhazardous 

oilfield waste (“NOW”) are exempt from hazardous waste regulation by federal law because they 

are produced from the exploration, development, or production of hydrocarbons and thus fall 

under what is generally referred to as the oil and gas waste exemption found in 40 CFR Part 

261. Thus, even if an oilfield waste has characteristics that would otherwise render it hazardous 

under 40 CFR Part 261, its origin in the exploration, drilling, or production of hydrocarbons 

generally renders it exempt from federal hazardous waste regulations. Although none of the 

states listed above have chosen to regulate oilfield waste as hazardous waste, a state has the 

option of doing so, and California, for one, does. The used oils, oily wastewater, and filters 

associated with the maintenance and repair of machinery used in oil and gas drilling and 

production are not subject to the oil and gas waste exemption but are classified as
94

nonhazardous by federal definitions. As such, regulation of these materials are covered by 

other, less expansive federal regulations and tend to vary more from state to state. Oil

producers are specifically allowed by the terms of these exemptions to commingle their used 

machine oils with their produced crude oil, but refineries discourage the practice because it 

presents them with processing problems. 

Waste fluids and solids containing Naturally Occurring Radioactive Materials (NORM) are

subject to state regulations that require special handling and disposal techniques. There are 

currently no federal regulations governing NORM. Each state regulatory agency sets the

threshold level of radiation for classifying waste as NORM. The threshold level for classification 

as NORM ranges from 30 picoCuries per gram (pCi/g) to 50 pCi/g. The special handling and 

disposal requirements for NORM generally result in the segregation of these materials from 

NOW and in substantially higher disposal costs when managed by commercial disposal firms.

Disposal of oil and gas NORM waste in Texas is regulated by 16 TAC Part 1, §3.94. In general, 

NORM, including treated NORM within 5 piC/g of background is eligible for on-site disposal by 

injection into a well that will be plugged. It may also be injected in a well on another lease with 

written permission from the owner. Commercial disposal of NORM is available in Texas at two 

different sites. Alabama has not fully developed its NORM regulatory program, but waste within 

5 piC/g of background is considered acceptable for on-site disposal.

NORM waste generated in Mississippi, Alabama and Florida is typically shipped to Louisiana or 

Texas. In Louisiana, oil and gas production waste with NORM levels of 30 piC/G or less may be 

disposed as NOW.

Differences in laws among the states lead to differences in waste management methods as well 

as industry preferences in siting of waste facilities in certain states. The substantive differences 

that distinguish the states are comparatively few. Texas allows and regulates salt dome disposal 

of waste, while no other state does. Louisiana, Alabama and Mississippi allow the landfilling of 

used oil filters and oil-based drilling muds, while Texas requires them to be recycled. Texas 

generally has stricter limits on hydrocarbon content of waste going into municipal landfills. 

Texas has regulations allowing oil-based drilling mud to be recycled through bioremediation into 

road-building material, while none of the other states have enabled oilfield waste land

application recycling operations in their regulatory framework.

6.5 Industry Trends and Outlook

Florida Gulf Coast: For the purpose of this analysis, we have assumed that Florida’s waste 

disposal regulations, as they now exist, will remain static as they pertain to disposal of any 

wastes that may come ashore there associated with OCS drilling. Special accommodations to 

the unique requirements of offshore oil and gas waste are not likely. This section will address 

the following questions:

• What waste management facilities can be legally used or developed under Florida 

regulations? 

• What geological or land use considerations hinder or help the development of such 

facilities?

• What are the economics of using existing local facilities or developing new ones 

versus transporting waste back to facilities in established OCS support bases?
95

Transfer Facilities: Florida has adopted the transfer facility requirements listed in 40 CFR 265 

Subparts B, C, D, and I. Nothing in these regulations would appear to prohibit a transfer 

operation similar to the ones operated by Newpark along the Louisiana and Texas Gulf Coast.

Subsurface Injection: Subsurface injection in Florida for oil and gas waste is allowed under 

rules much like U.I.C. programs in other states. These rules were developed to regulate 

Florida’s tiny land-based oil and gas industry in the western panhandle of the state. Whether 

such wells would be technically and legally feasible in a proximity to a port that may develop 

capabilities to serve offshore drilling is a question that has not been examined.

Landfills: Waste coming ashore from OCS activities would invite some of the same opposition 

that Floridians have already expressed with respect to cruise ship waste, which has sometimes 

been disposed of in communities where these volumes had a material impact on capacity

available for locally generated waste. Although outright restrictions on the importation of waste 

by a state has been found to be a violation of the commerce clause of the United States 

Constitution, terms of a landfill permit often restrict the served market of a particular landfill to a 

certain radius, which could result in an effective prohibition against receipt of OCS waste. If 

such prohibitions were implemented successfully, they would render Florida impractical as an 

operating base for supply boats.

Land Application: Land application of oilfield materials does not appear to be allowed under 

Florida rules.

Salt Cavern Disposal: Salt cavern disposal is not allowed under Florida rules.

Separation and Reclamation of Drilling and Completion Fluids: Only storage regulations relating 

to these types of chemicals would come into play and no significant barriers to reclamation 

exist. Fluid selections for wells closer to Florida will be determined by the drilling conditions 

encountered and could possibly be chemically different from those used elsewhere in the Gulf.

Conclusions: Florida is not expected to develop special-purpose regulations to accommodate 

OCS waste, but nevertheless, limited waste management activities might develop there, under 

the assumption that any support activities develop in Florida. A successful restriction of Florida 

landfills’ service area could possibly serve as an effective barrier against an offshore marine 

service center developing in Florida.
97

7.0 PIPELINES

7.1 Introduction

After raw gas is brought to the earth’s surface, it is processed – to remove impurities such as 

water, carbon dioxide, sulfur or inert gases – and transformed into a saleable, useful energy 

source. It is then moved into a pipeline system for transportation to an area where it is sold. 

Because natural gas reserves are not evenly spaced across the continent, an efficient, reliable 

gas transportation system is essential.

Over 200,000 miles of steel pipe, ranging in diameter from 20 to 42 inches, serve as the

“interstate highway” system for natural gas throughout the U.S. (Figure 7.1). As of June 2001, 

there were approximately 44,218 km (27,569 mi) of pipeline on the seafloor of the Gulf (USDOI, 

MMS 2001b). MMS (2000a) provides a detailed description of offshore pipeline installation 

methods, seafloor spanning, and maintenance of flows. When moved through a pipeline, 

natural gas is transmitted at higher pressures to reduce the volume and to provide force to

propel the gas through the pipeline. In order to maintain the level of pressure, the gas needs to 

be compressed periodically as it moves through the pipeline. Therefore, compressor stations 

are installed every 70 to 100 miles along each pipeline. 

When transmission pipelines deliver gas to utilities, the fuel passes through a “gate station” or 

“city gate”. The pressure in the pipeline is reduced from transmission levels – usually anywhere 

from 200 to 1,500 pounds per square inch – to distribution levels – 1 to 200 pounds per square 

inch. Meters at the gate measure how much gas is being received by the utility, and a soursmelling odorant is added to help customers smell even small quantities of natural gas. The 

local utility then uses distribution pipes, or mains, to bring natural gas service to home and 

businesses (Interstate Natural Gas Association of America 2000).

Figure 7.1. Natural Gas Pipes.

Source: Natural Gas Information and Educational Resources (1998a) 
98

7.2 Description and Typical Facilities

The need for new or additional pipeline capacity can be implemented in several ways. Pipeline 

designers have various options available, each with its own physical and financial advantages 

and disadvantages. Some of the options for adding new natural gas transmission capacity 

include building a new pipeline, converting an oil or product pipeline or expanding an already 

existing system. The least expensive option, often the quickest and easiest, and usually the 

one with the least impact environmentally, is to upgrade facilities on an existing route. However, 

this may not be feasible, especially if the market to be served is not currently accessible to the 

pipeline company (Energy Information Administration 1999a).

On average, an interstate construction/expansion project may take about 3 years from the time 

it is first announced until it is placed in service, even longer if it encounters major environmental 

obstacles or public opposition. 30 The life-cycle for a natural gas pipeline project involves 

several milestones. After first detecting market indications that enough potential need may exist 

in a particular supply or market area to support construction of new capacity, the sponsors of 

the project, be it a new pipeline or an expansion of an existing one, publicly announce their 

belief that a project of particular magnitude and location could be built if there is enough interest. 

To gauge the level of market interest, an open-season is held (1 to 2 months), giving potential 

customers an opportunity to enter into a nonbinding commitment to sign-up for a portion of the 

capacity rights available on the pipeline project. If enough interest is shown during the openseason, the sponsors will arrive at a preliminary project design and move forward.

The development of the final project design and obtaining firm financial commitments from 

customers may take from 2 to 3 months, after which the project specifications are filed with the 

appropriate regulatory agency. While there are no data available on the average length of time a 

project may require to receive a final determination from a State agency, generally a FERC

review takes from 5 to 18 months, with the average time being about 15 months. Usually, 

approval by the regulating authority is conditional, but most often the conditions are minor. 

Regardless, it is then up to the project sponsor to accept or reject the conditions or refile with an 

alternative plan. 

Construction typically is completed within 18 months following final regulatory approval, and 

sometimes in as little as 6 months. Construction of an approved project may be delayed 

because of the extended time required to acquire local permits from numerous towns and land 

use agencies located along the proposed construction route. In 2000, two major pipeline 

expansion projects were postponed until the summer of 2001 because they were unable to 

acquire all of the local approvals in time to construct and complete the project before the

beginning of winter.

Commissioning and testing of the completed pipeline project usually takes about 1 to 3 weeks 

and involves subjecting the completed segments of the projects to hydrostatic and other

required testing of the line in place. Line packing, or filling the line with the initial baseload gas 

volumes, is usually needed only on new pipelines or larger expansion projects.

 

30 The remainder of this subsection is taken from: Energy Information Administration, Natural Gas 

Transportation – Infrastructure Issues and Operational Trends, (Washington D.C.: Department of Energy), 

October 2001, p. 8.
99

Costs of Development: The cost of pipeline construction depends on the type of facilities 

being built and the distance involved. Usually, a new pipeline, for which right-of-way land must 

be purchased and all new pipe laid and operating facilities installed, will cost much more than an 

expansion of an existing route. The difference is demonstrated in Table 7.1, where the new 

pipeline projects averaged about $0.48 per cubic foot and an expansion, about $0.29 per added 

cubic foot (Energy Information Administration 1999a).

The major cost components associated with the building or expansion of a natural gas pipeline 

are usually placed under the following categories: labor (including survey and mapping), rightof-way acquisition, facilities (compressor stations, meter stations, etc.), materials (compressors, 

pipe, wrapping), and miscellaneous (administration, supervision, interest, Federal Energy

Regulatory Commission fees, allowances for funds during construction, and contingencies).

Generally, labor costs represent the largest component, although on new, long-distance pipeline 

projects, with pipe diameters greater than or equal to 36 inches, material costs approach labor 

costs. Right-of-way costs also represent a larger proportion of costs in the latter case (Energy 

Information Administration 1999a).

Table 7.1

 Major Additions to U.S. Interstate Natural Gas Pipeline Capacity (1991-2000)

All Type Projects New Pipelinesa Expansions

Year

No.

of

Project

s

System

Mileage b

New

Capacity

(MMcf/d)

Project

Costs

(million 

$)

Avg.

Cost

per 

Mile

($ 

000)c

Costs 

per

Cubic 

Foot

Capacity

(cents)

Avg.

Cost

per 

Mile

($ 000)

c

Costs 

per

Cubic 

Foot

Capacity

(cents)

Avg.

Cost

per 

Mile

($ 000)

c

Costs per

Cubic Foot

Capacity

(cents)

1996 26 1,029 2,574 552 448 21 983 17 288 27

1997 42 3,124 6,542 1,397 415 21 554 22 360 21

1998 54 3,388 11,060 2,861 1,257 30 1,301 31 622 22

1999 36 3,753 8,205 3,135 727 37 805 46 527 31

2000 19 4,364 7,795 6,339 1,450 81 1,455 91 940 57

Total 177 15,658 36,176 14,284 862 39 1,157 48 542 29

Notes:

a

 New pipelines include completely new systems and smaller system additions to existing pipelines, i.e. a lateral 

longer than 5 miles or an addition that extends an existing system substantially beyond its traditional terminus.

b

 Includes looped segments, replacement pipe, laterals, and overall mileage of new pipeline systems.

c

 Average cost per mile is based upon only those projects for which mileage was reported. For instance, a new 

compressor station addition would not involve added pipe mileage. In other cases final mileage for a project in 

its initial phases may not yet be final and not available. In the latter case, cost estimates may also not be 

available or be very tentative.

Source: Energy Information Administration (1999a) 
100

Monitoring and Maintenance of Pipelines: “The huge investment in pipe, pumps,

compressors, drivers, control systems, and other equipment and the cost of downtime make 

maintenance of pipeline systems critically important” (Kennedy 1993). Combining preventative 

maintenance (such as cathodic protection and pipeline coating, discussed further in Chapter 8), 

frequent inspection and the selection of steel with the proper properties for a specific service 

makes oil and gas pipelines one of the safest industrial operations. 

Traditionally, pipelines were inspected visually by going over the route on the ground or

patrolling the pipeline route in aircraft. Aerial inspection is still done, but today instrumentation 

and monitoring equipment provide more rapid and precise location of leaks or potential leaks.

Today, pipelines are monitored 24 hours a day, 365 days a year. Data acquisition systems, or 

SCADA are computerized systems that allow pipeline operators to keep accurate, constant 

information on sections of pipeline. Information can be retrieved from remote sections of

pipeline and the flow of gas can be controlled by using computers that are linked to satellite 

communication and telephone communication systems. SCADA systems allow not only

pipeline operators to obtain timely information, but they also allow producers to have access to 

some of the same information so they can purchase distribution services according to the

current volume of gas in a pipeline (Natural Gas Information and Educational Resources

1998b).

One method that pipeline companies use to maintain their pipelines is through the use of

intelligent robotic inspection devices, know as PIGs. These PIGs are able to travel through a 

pipeline, inspecting the interior walls for corrosion and defects, measuring the interior diameter 

of a section of pipe, and removing accumulated debris from a section of pipeline. The PIG uses 

sensors to take thousands of measurements that can later be analyzed by computers to show 

possible problems. Magnetic-flux leakage PIGs are used to detect metal loss (from corrosion –

see below) in pipeline walls, locating potential problems without the cost and risk of using other 

methods.

Although cathodic protection is used for many newer sections of pipelines, corrosion is still a 

potential problem that weakens some parts of the pipeline. Cathodic protection refers to the 

method of mitigating corrosion in metal structures that involves using electric voltage to slow or 

prevent corrosion. It is used along natural gas pipelines, as well as in certain bridges or other 

large metal structures that need to resist corrosion over an extended period of time. Cathodic 

protection is discussed in more detail in Chapter 8 – Pipe Coating.

Pipeline Repair: If a leak is discovered, the method of repair may vary. A short length of pipe 

may be inserted where the leak is found (called a “pup joint”), or the entire joint of the pipe may 

be replaced. Onshore pipelines may also be plugged temporarily on either side of a problem 

area, and flow is redirected through a bypass so work can be done on the isolated area. A 

variety of plugging equipment is available, and can be applied in a wide range of situations.

The repair of offshore pipelines is much more complex and costly. Each repair alternative is 

reviewed to ensure the selection of the method that is most compatible with the overall 

requirements of each situation. “Factors which should be taken into account here are location, 

water depth, [pipeline] size, amount of coverage, age, design and operating pressures, vessel 

traffic in the area, special hazards (i.e., mud slides, unusual currents, severe weather

conditions, etc.) as well as any other special conditions under which the pipeline is operating”

(Woods 1982). The importance of the pipeline to the producing field should also be considered. 
101

To minimize the downtime of an out-of-service line, formal emergency repair plans are often 

made for offshore pipelines. There are a variety of methods available for repairing underwater 

pipelines, but they generally fall into three categories (Woods 1982):

• Surface repair: This method involves lifting the pipeline to the surface and repairing 

it completely by welding a new section of pipe to replace the damage area or by 

welding flanges, misalignment fittings, etc. onto each end of the pipe after removal of 

the damaged area. The pipe is then lowered back to the sea floor and carefully 

reconnected. Since this method relies upon all major work being performed on the 

surface, it is probably the most weather sensitive of the three types of repair

methods.

• Underwater hyperbaric welding: If a totally welded repair without lifting the pipe is 

the most desirable solution, then this can be achieved on the bottom, eliminating the 

necessity of raising the pipeline to the surface. The variations on this method allow 

for a welder-diver to weld the pipe either completely enclosed in a dry habitat or with 

the welder-diver working in the wet while the weld point on which he is working is 

enclosed in a dry, environmentally controlled chamber. Although not as weather 

sensitive as surface repairs, underwater welding is probably the most skill-sensitive 

method due to the fact that specific qualification levels for welding the pipe material 

at a given water depth must be present in the welding team.

• Mechanical connectors: There are a number of these types of products currently 

available which allow for the repair of pipelines in place without the necessity of lifting 

them to the surface or performing underwater welding. These products are available 

in a variety of configurations and degrees of sophistication ranging from the

containment of a pin-hole leak with a simple split-sleeve clamp through a complete 

spool-piece repair in deep water either through diver intervention or in an automatic, 

diver-less profile. Generally, this method is not as weather or skill sensitive as the 

other two but, due to the manufacturing lead time of many of these items, it is almost 

imperative that they be purchased and stocked well in advance of any requirement.

“It must be noted that this is a very general review of the most typical approaches and that many 

combinations of these and other methods have been used. Also, there is a great deal of 

attention now being focused on the problem, and quite a bit of development work is being 

carried out by contractors and manufacturers in an effort to improve on the cost and jobsite 

efficiency of their methods and equipment” (Woods 1982).

7.3 Industry Characteristics

Trends

Oil: During 2002, the U.S. produced approximately 8.1 million barrels per day of oil, of which 

5.8 million bbl/d was crude oil, and the rest natural gas liquids and other liquids. U.S. total oil 

production in 2002 declined by 24 percent from the 10.6 million bbl/d averaged in 1985. U.S. 

crude oil production, which declined after the oil price collapse of late 1985 and early 1986, 

leveled off in the mid-1990s, and began falling again following the sharp decline in oil prices of 

late 1997 and early 1998. Since March 1999, however, world oil prices have rebounded and 

U.S. crude production leveled off in 2000 and 2001, but then rose again in 2002. 
102

U.S. crude production still remains near 50-year lows. However, exploration and development 

spending has been increasing, and improved technology and increases in offshore production 

have also been boosting production levels. Crude oil production in the lower 48 states is 

expected to increase slightly in 2003, to 4.85 million bbl/d, while Alaskan crude production is 

expected to fall slightly to 0.95 million bbl/d. Deepwater production has been increasing rapidly 

and now accounts for about two-thirds of total Gulf output. 

Gas: Domestic dry natural gas production fell by 1.8 percent in 2002, but is expected to

increase by approximately 1.4 percent in 2003. Strong increases in U.S. natural gas production 

and net imports will be needed over the next two decades to meet demand – which increased 

by 21 percent from 1990 through 2002. Increased natural gas production is expected to come 

mainly from onshore sources, although offshore Gulf production also is forecast to grow

significantly. In August 2001, for instance, ExxonMobil began production at its $330 million 

Mica natural gas project in the deepwater Gulf. Alaska's North Slope fields also represent a 

large potential natural gas source, with an estimated 30-35 tcf of natural gas reserves. 

Future increases in natural gas production likely will come mainly from lower 48 sources, with 

increased use of cost-saving technologies expected to result in continuing large natural gas 

finds, including in the deep waters of the Gulf but also in conventional onshore fields. Currently, 

top natural-gas-producing states (in descending order) include Texas, Oklahoma, New Mexico, 

Louisiana, Wyoming, Colorado, Alaska, Kansas, California, and Alabama. 

Overall, the United States depends on natural gas for about 24 percent of its total primary 

energy requirements (oil accounts for around 39 percent and coal for 23 percent).

Liquified Natural Gas (LNG): According to industry experts, the Gulf coast is the most promising 

location for LNG terminals and plants (Daily 2003). The push to construct LNG plants has been 

driven by decreasing North American production and USDOE predictions that natural gas 

demand will increase from the current 22 tcf to 35 tcf by 2025. Approximately half of the more 

than 30 proposed plants to process LNG are planned for the Gulf. Cheniere LNG (part of 

Cheniere Energy, Inc.) applied for a permit for a plant in Texas and was expected to seek 

approval for two more by the end of 2003 (Daily 2003). Sempra Energy received preliminary 

approval to build a $700 million, 1.5 bcf per day plant in Louisiana. The four active LNG 

terminals in the U.S. have a total capacity of 2.6 bcf a day.

Natural Gas Pipelines: The United States has a complex, extensive pipeline infrastructure for 

transporting natural gas from production areas to ultimate consumers. More than 80 U.S. 

interstate pipeline companies operate over 200,000 miles of mainline transmission lines,

hundreds of compressor stations, and numerous storage facilities, allowing gas delivery

throughout the lower 48 States (Figure 7.2). About 50 of these pipelines are characterized as 

major by the Federal Energy Regulatory Commission (FERC). Another 60 or so pipelines 

operate only within the borders of individual states – in the intrastate market – the intrastate 

portion of the pipeline system accounts for another 73,000 miles of pipelines (Energy

Information Administration 2001a).
103

Over the past decade, natural gas consumption grew by 17 percent. During this time (1991 

through 2000), enough pipeline capacity was installed to satisfy demand as it grew. Natural gas 

pipeline capacity grew in excess of 5 Bcf/d per year, totaling almost 20 Bcf/d. At least 65 

natural gas pipeline construction projects were completed and placed into service in the United 

States: 35 in 1999 and 30 in 2000 (Energy Information Administration 2001a). During this time, 

very few capacity constraints or bottlenecks were observed with little or no disruptions in 

service. “However, in the past year, the demand for natural gas pipeline capacity appears to 

have approached its limit in some fast-growing market areas such as California and New York. 

In most cases though, the conditions that have contributed to these situations appear to be 

short term in nature and readily resolved” (Energy Information Administration 2001a). More 

detailed discussion of capacity additions and construction projects can be found below, in

Section 7.5 - Industry Trends and Outlook.

Oil Pipelines: In addition to natural gas pipelines, there are petroleum or oil pipelines that carry 

nearly two-thirds of the ton-miles of oil transported in the U.S. There are approximately 200,000 

miles of oil pipe that move domestic crudes from producing areas like California, the Rockies 

and West Texas and imported crudes from receiving ports. The U.S. also relies on pipelines to 

transport petroleum products from refining centers, such as the Gulf Coast, to consuming

regions, like the East Coast. As the primary option for transcontinental transportation, pipelines 

are much more cost-effective than any alternative such as rail, barge or road. Replacing even a 

modest-sized pipeline, which might transport 150,000 barrels per day, would require 750 tanker 

Western

Central

Midwest

Northeast

Southeast Southwest

298

423

4,412

51

3,673

66

1,219

5,487

2,604

8,878

12,867

3,054

3,267

3,329

4,887

2,090

2,956

532

5,480 9,821

405

565

1,093

21,311

Western

Central

Midwest

Northeast

Southeast Southwest

298

423

4,412

51

3,673

66

1,219

5,487

2,604

8,878

12,867

3,054

3,267

3,329

4,887

2,090

2,956

532

5,480 9,821

405

565

1,093

21,311

Figure 7.2. Estimated Region-to-Region Natural Gas Pipeline Capacity at the End of 2000 

(MMcf/d).

Source: Energy Information Administration (2000a) 
104

truck loads per day, a load delivered every two minutes around the clock (Association of Oil 

Pipelines 2003a).

Interstate oil pipelines deliver over 13 billion barrels of petroleum each year. About 59 percent 

of the petroleum transported by pipelines is crude oil, the remainder is in the form of refined 

petroleum products. As previously noted, the oil market’s infrastructure moves oil from the

producing regions to consuming regions. The profiles below and accompanying Figure 7.3 and 

Table 7.2 display the inter-regional flows in the U.S:31

• The Gulf Coast (PADD 3)32 is the largest supply area of the U.S. accounting for 55 

percent of the nation’s crude oil production and 47 percent of its refined product 

output. It is the largest oil supplier in interregional trade, accounting for 90% of the 

crude oil shipments and 80% of the refined petroleum production shipments among 

PADDs. Most of the crude oil goes to refineries in the Midwest, while most refined 

products go to the East Coast and, to a lesser extent, to the Midwest.

• The East Coast (PADD 1) has virtually no indigenous crude oil production, limited 

refining, and the highest regional, non-feedstock demand for refined products. Its 

refineries process predominately foreign crude oil. To meet regional demand, their 

output is augmented by refined product shipments from the Gulf Coast as well as 

imports from abroad. The East Coast receives more than 60% of the refined 

products shipped among regions and almost all of the refined product imported into 

the U.S.

• The Midwest (PADD 2) has significant regional crude oil production, but also

processes crude oil from outside of the region: Canadian crude oil imported directly 

via pipeline, crude oil imported from other nations and then shipped to the Midwest 

via the Gulf Coast, and crude oil produced in the Gulf Coast region. These supplies 

from outside of the region – imports and domestic – account for 88% of its refinery 

input. Refined product output from regional refineries is also supplemented with 

supplies from outside the region, primarily shipments from the Gulf Coast.

• The Rocky Mountain Region (PADD 4) has the lowest petroleum consumption, but 

has shown relatively rapid regional growth in recent years. It imports crude oil from 

Canada to augment local production for its refineries. Its distances are long, its 

topography steep and its infrastructure thin, however. Therefore, the inter-regional 

trade, while small in nationwide standards, is an important factor in keeping the 

region’s supply and demand in balance.

• The West Coast (PADD 5) is logistically separate from the rest of the country. Its 

crude oil supply is dominated by production from the Alaskan North Slope oil fields, 

which now accounts for 55% of PADD 5 production, down from 65% when those

fields were in peak production in the late 1980s. Essentially all of the rest of the 

region’s production comes from California. Because of unique product quality

 

31 This section taken from: Allegro Energy Group. 2001. How Pipelines Make the Oil Market Work –

Their Networks, Operation and Regulation, (Prepared for the Association of Oil Pipe Lines and the 

American Petroleum Institute’s Pipeline Commission). 22 pp.

32 The five regions referred to as “Petroleum Administration for Defense Districts,” or PADDs, were 

delineated during World War II. 
105

requirements in California, the largest consuming state, essentially all of that state’s 

refined product demand is met by output from the state’s refineries.

3.7

0.17

2.2

0.02

1.4 12.1 2.0

32.7

2.7

7.2

0.1

2.8

31.0

6.0

66.6

1.2

0.03

8.6

7.3

93.5

18.0

67.0

412.0

Federal Offshore

(PAD District III) 

567.8

17.7

16.9

13.7

54.7

0.06

258.0

0.6

Federal Offshore

(PAD District V) 

29.8

3.7

0.17

2.2

0.02

1.4 12.1 2.0

32.7

2.7

7.2

0.1

2.8

31.0

6.0

66.6

1.2

0.03

8.6

7.3

93.5

18.0

67.0

412.0

Federal Offshore

(PAD District III) 

567.8

17.7

16.9

13.7

54.7

0.06

258.0

0.6

Federal Offshore

(PAD District V) 

29.8

Figure 7.3. Production of Crude Oil by PAD District and State (million barrels).

Source: Energy Information Administration (2003a) 
106

Pipelines are an essential mode for moving oil between regions. In 2000, for instance, pipelines 

moved nearly all of the crude oil and about 70 percent of the products transported between 

PADDs. “Pipelines are also irreplaceable in moving oil within the PADDs, from producing fields 

and coastal ports to refineries (crude oil and other refinery feedstocks) and from refineries and 

large redistribution centers to smaller regional supply centers, to airports, and even directly to 

large consumers (refined petroleum products)” (Allegro Energy Group 2001).

Gulf of Mexico: The Federal offshore region of the Gulf of Mexico has become an increasingly 

important source of natural gas – expanding from 16 to 51 producing fields from 1997 to 2001. 

Deepwater production rates have risen by well over 100,000 barrels of oil per day and 400 

million cubic ft of gas per day, respectively, each year since 1997 (USDOI, MMS 2002a). “This 

stands in impressive contrast to just two decades ago when the Gulf of Mexico was considered 

to be a mature oil and gas region with limited potential for further discovery and development. 

In fact, the region was so lacking in promise that it was then called the ‘Dead Sea.’ A 1973 

Table 7.2

Movements of Crude Oil and Petroleum Products by Pipeline Between PAD Districts, 2002 

(thousand barrels)

Crude Petroleum

Oil Products Total

---------- (thousand barrels) ----------

From PAD I to:

PAD II - 108,705 108,705 

PAD III 3,043 - 3,043 

From PAD II to:

PAD I 2,479 12,806 15,285 

PAD III 12,159 51,719 63,878 

PAD IV 11,901 22,633 34,534 

From PAD III to:

PAD I - 857,497 857,497 

PAD II 654,447 306,947 961,394 

PAD IV - 18,813 18,813 

PAD V - 33,411 33,411 

From PAD IV to:

PAD II 32,747 22,469 55,216 

PAD III 8,112 55,565 63,677 

PAD V - 11,287 11,287 

From PAD V to

PAD III - - - 

PAD IV - - - 

Source: Energy Information Administration (2003a) 
107

report by the U.S. Department of the Interior stated that all potentially productive blocks in water 

depths up to 600 feet in the Federal Offshore Louisiana would be leased by 1978 and all 

exploration and development would be completed by 1985” (Energy Information Administration 

1999a). To the contrary, the offshore drilling industry in the Gulf has come a long way. The 

Gulf represents an expanding frontier with extraordinary growth – especially of deepwater – oil 

and gas industry activity over the past 7 years. 

According to a recently released MMS report, “[t]he large volume of active deepwater leases, 

the increased drilling program, and the growing deepwater infrastructure all indicate that the 

deepwater GOM will increase in importance as an integral part of this nation's energy supply 

and will remain one of the world's premier oil and gas basins” (USDOI, MMS 2002a). Even in 

recent years, the oil and gas industry in the Gulf has witnessed an incredible expansion

(USDOI, MMS 2002a): 

• While only 16 deepwater projects were on production in early 1997, this number 

grew to 51 by the end of 2001. 

• A record 14 deepwater projects initiated production during 2001, and another 13 are 

projected to begin in 2002. 

• By the end of 2001, deepwater oil production had risen 500 percent and gas

production had risen 550 percent since 1995. 

• Fifty-nine percent of all oil production in the Gulf now comes from the deepwater.

An essential factor needed for supporting these expanding offshore supply operations is

adequate transmission capacity to move supplies to onshore pipelines and then to market. In 

1998 alone, an additional 2.6 bcf/d of pipeline capacity was completed to increase flow to 

onshore Louisiana (Energy Information Administration 1999a). As previously noted, further 

discussion of recent offshore capacity expansions can be found in Section 7.5 – Industry Trends 

and Outlook. 

According to Table 7.3, there is currently over 12,000 miles of offshore pipeline in the Gulf of 

Mexico. Almost 88 percent are off the coast of Louisiana, with Central and Western Louisiana 

making up the greatest proportion (71 percent). Ninety-two percent of pipe over 27 inches in 

diameter is found off the coast of Louisiana, the greatest amount (66 percent) from Western 

Louisiana. Texas accounts for 8 percent of pipe greater than 27 inches in diameter. 
108

7.4 Regulations

Natural Gas Pipelines: Interstate natural gas pipelines are regulated by the Federal Energy 

Regulatory Commission (FERC). FERC regulates both the construction of pipeline facilities and 

the transportation of natural gas. It is important to note however, that FERC does not have 

jurisdiction over all gas transmission. Gas pipelines that are restricted to intrastate operation 

are regulated by the States in which they operate and are not subject to FERC authority. These 

intrastate pipelines are a significant part of gas transportation capacity in some states,

especially those that produce large quantities of gas such as Texas, Louisiana, and Oklahoma. 

Under the Natural Gas Act of 1938, FERC regulates both the construction of pipeline facilities 

and the transportation of natural gas in interstate commerce. Companies providing services 

and constructing and operating interstate pipelines must first obtain Commission certificates of 

public convenience and necessity. In addition, FERC approval is required to abandon facility 

use and services, as well as to set rates for these services. FERC oversees construction and 

Table 7.3

Summary of Federal Offshore Pipeline Miles by Area and Diameter in the Gulf

Miles by Area and Diameter

Diameter

Eastern 

Louisiana

Central 

Louisiana

Western 

Louisiana Texas

Eastern 

Gulf Total

< 8" 952 1,735 1,528 616 117 4,949

> 8"-18" 721 1,440 1,628 432 42 4,262

19"-27" 368 989 575 249 24 2,206

> 27" 52 284 874 105 1,315

Total 2,093 4,448 4,605 1,402 182 12,730

Percent of Total Miles by Area

Diameter

Eastern 

Louisiana

Central 

Louisiana

Western 

Louisiana Texas

Eastern 

Gulf Total

< 8" 19% 35% 31% 12% 2% 100%

> 8"-18" 17% 34% 38% 10% 1% 100%

19"-27" 17% 45% 26% 11% 1% 100%

> 27" 4% 22% 66% 8% 0% 100%

Total 16% 35% 36% 11% 1% 100%

Source: Foster Associates (1998) 
109

operation of facilities needed by pipelines at the U.S. point of entry or exit to import or export 

natural gas.

FERC’s Transformation of the Pipeline Industry: Until the 1980s, pipeline systems brought 

natural gas from producers, transported it along their pipelines, and then resold it to local

distribution companies (LDC's). In 1985, Order 436 initiated a transformation of the natural gas 

transportation industry, which culminated in Order 636 in 1992. These two orders (with a 

number of additional orders in between) effectively unbundled these services so that interstate 

pipeline companies no longer own the gas transported on their pipeline systems, but transport it 

for third parties. Purchasers of natural gas now can negotiate price provisions and contract 

terms with various suppliers, while contracting separately with pipeline companies for

transportation, storage, and numerous other services, selected and combined, to satisfy their 

needs.33

Order 436 ruled that a pipeline could choose “open-access” status – offering to transport gas 

purchased by any of its customers. Customers not choosing transportation could continue to 

use the resale services previously offered by the pipelines. If a pipeline did not choose to offer 

open-access, it would provide resale service only and not be allowed to transport any third party 

gas. FERC enticed the pipelines by offering to grant those that did choose open-access an 

“optional expedited certificate” for new facilities. Traditionally, obtaining a permit to build new 

facilities would mean a costly and often contested FERC proceeding that could take years. 

FERC presumed that a company looking for an optional expedited certificate had a project that 

was in the public interest if the pipeline was willing to bear the risk. “A pipeline that wished to 

compete needed open-access, since otherwise all of its projects risked delays in certification. 

Order 436 changed the industry. Within months every important interstate pipeline had applied 

for open access status. Within two years, 75 percent of all interstate throughput was

transported rather than resold” (Michaels 2002a).

Order 436 was successful in encouraging the start of competition in the natural gas

transportation industry. However, there were problems with FERC’s neglect of take-or-pay 

issues.34 The DC Court of Appeals wanted FERC to address the possible conditioning of a 

producer’s access to a pipeline on the resolution of take-or-pay contracts. The Court

sympathized with FERC’s reluctance to alter contracts. However, these contracts had been 

written in the all resale era as a response to regulation that required, then resale only, pipelines 

to find adequate gas supplies in a shortage period. Thus, FERC should have the power to 

modify them if the regulatory order changed. 

In response to the Court of Appeals remand, FERC issued Order 500 in August, 1987. Order 

500 required that a producer credit any gas transported for it against the transporting pipeline’s 

take-or-pay liability. To minimize the intrusion, Order 500 mandated cross crediting only on a 

subset of all contracts that had been written during 1986 and 1987. To force rapid settlements, 

the Order imposed a sunset deadline of December 31, 1988. And, to avoid further take-or-pay 

 

33 Unless otherwise noted, the source for this subsection is: Robert J. Michaels. “The New Age of 

Natural Gas. How Regulators Brought Competition.” Regulation; The Cato Review of Business & 

Government, <http://www.cato.org/pubs/regulation/reg16n1e.html>, (27 May 2002).

34 Take-or-pay is a contract clause in a gas supply contract that provides a minimum quantity of gas 

that must be paid for, whether or not delivery of that gas is accepted by the purchaser, for a specified 

period. Most contracts contain a time period in which the buyer may take delivery of the gas without 

penalty.
110

problems, FERC adopted the ratemaking principle of a gas inventory charge, which would

compensate the pipeline for standing ready to provide its resale customers’ requirements.

With transported gas still dominating their throughput, pipelines still entered the 1990s with 

residual responsibilities to those customers who still elected resale service. They also remained 

responsible for reliable operation and for coordinating receipts, deliveries, and storage, both for 

themselves and for the third-party transporters. Most pipelines owned marketing affiliates that 

sold gas in competition with producers and brokers. Transporters were concerned that a 

pipeline could use its operational knowledge and its information about their transactions to 

advantage itself as a gas merchant, particularly during peak periods. Conversely, pipeline 

resales were disadvantaged by burdensome abandonment regulations that did not apply to 

transport service. 

To address these and other issues, in April 1992, FERC issued Order 636, completing the 

transformation of the natural gas transportation industry. This final restructuring rule mandates 

transportation “basis that is equal in quality for all gas supplies whether purchased from the 

pipeline or from any other gas supplier.” The ruling issues blanket sales certificates to pipelines 

so that they can offer unbundled firm and interruptible sales services at market-based or

competitive rates. In addition, pipelines will be required to provide a variety of transportation 

services to their shippers. This includes a new unbundled "no-notice", firm transportation 

service, firm transportation service that is unbundled and improved in quality, unbundled storage 

services, and interruptible transportation services, among others. The order permits gas

purchasers and gas sellers to choose the exact transportation service that they want, including 

a combination of services that will ensure that the pipelines can deliver an adequate supply of 

gas to the city gate from various sources when that supply is needed.35 

The Order also loosened requirements that a pipeline continue to provide services that are 

uneconomic. Under Order 636, transportation rates were updated to conform to the straightfixed variable method – a method which puts all fixed-costs in the capacity charge, and all 

variable costs in the transport charge. These new rates make users responsible for the costs of 

capacity that they actually use in peak periods. “Converting pipelines into transporters allows 

customers the benefits of being able to search for attractive purchases, rather than obligating 

them to take whatever gas the pipeline chooses to buy. Allowing customers to resell their 

pipeline rights further increases their options. The advent of open access transportation and a 

market in released capacity provided an important lesson in economics: although a pipeline is 

technologically a natural monopoly, a market is arising in which the services of that monopoly 

will be allocated competitively” (Michaels 2002b).

Since Order 636, competition has increased among sellers, and a strong resale market for 

transportation capacity on interstate pipelines has developed. Numerous new services have 

also been introduced as companies positioned themselves to take advantage of new market 

opportunities. In response to new market conditions, many pipeline companies have

consolidated or formed strategic alliances to increase market share and gain access to new 

customers. For example, the gas industry has seen a strong growth in the number of gas 

marketing affiliates and “all energy” service companies. 

 

35 Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, Federal Energy Regulatory 

Commission, 59 FERC ¶ 61, 030, Order 636, April 8, 1992.
111

Purchasers of natural gas now can negotiate price provisions and contract terms with many 

different suppliers, while contracting separately with pipeline companies for transportation,

storage, and various other services, selected and combined, to satisfy their needs. To facilitate 

this, a new type of industry player has emerged, the independent gas marketer, who in addition 

to marketing gas supply can serve as the purchaser's agent in making all the arrangements 

necessary to get the gas delivered; providing, in essence, a "package" of sales and

transportation services. Deregulation and market restructuring have directly contributed to

growth in gas storage for managing seasonal inventories, the development of a secondary 

transportation market, and better information about commodity and transportation prices via 

commodity markets and electronic bulletin boards. Price signals for natural gas are quickly 

transmitted between the consumer and the producer, and regional markets are more integrated

(Natural Gas Information and Educational Resources 1998b).

Oil Pipelines: Like natural gas pipelines, most interstate liquid petroleum pipelines operate as 

“common-carriers” – pipelines must allocate space to all shippers who meet their conditions of 

service. FERC regulates the rates that an interstate pipeline can charge for service. (States 

generally also regulate rates for intrastate pipelines.) Prior to FERC rate regulation, the 

Interstate Commerce Commission determined an oil pipeline’s tariff rates to be “just and

reasonable” based on an allowed rate of return on the “valuation” of the pipeline’s common

carrier assets. When the FERC assumed jurisdiction, it explored a number of different methods 

for determining “just and reasonable” rates.

Under a regulatory system established in 1995, an interstate oil pipeline carrier may use a 

variety of methods to justify new tariff rates. These include a percentage change in accordance 

with a government-set economic index, application of market based rates, application of the 

former cost of service standard and negotiated rates for service that have been agreed to 

between the oil pipeline carrier, and relevant shippers. The vast majority of oil pipeline industry 

tariff rates now in effect were set under the economic index method. The second most used 

method of tariff rate justification is agreement on negotiated rates between the pipeline and its 

shippers. The fastest growing application is market-based rates, which requires the

Commission to determine that the pipeline lacks market power in the applicable regional market.

In addition to economic regulation, the design, construction, operation and maintenance of 

interstate liquid petroleum pipelines is regulated by the Department of Transportation’s Office of 

Pipeline Safety (OPS). If the pipeline is an intrastate pipeline and the state has established an 

office overseeing pipeline safety, there may be additional state regulatory requirements. In 

some cases, states have received approval from the federal OPS to inspect interstate pipelines 

for compliance with federal pipeline safety regulations, although enforcement authority remains 

under the jurisdiction of the federal OPS to assure continuity in interstate commerce. Offshore 

pipelines (e.g., in the Gulf of Mexico) are regulated by the Minerals Management Service.

Pipeline safety regulations govern the entire life of pipeline operations, including design, 

construction, inspection, record-keeping, worker qualification, and emergency preparedness. 

Other agencies have complementary regulatory jurisdictional roles related to pipeline safety 

such as:

• National Transportation Safety Board for investigation of certain pipeline

accidents;
112

• Occupational Safety and Health Administration for worker safety and hazardous 

material emergency response; 

• Environmental Protection Agency (and/or corresponding state environmental

agencies) for permitting of emission from tanks and some other facilities and 

response and remediation of liquid petroleum spills;

• U.S. Coast Guard relative to preparedness and response to spills in navigable 

waters; and 

• State and County Emergency Management Agencies may have regional

emergency planning and notification requirements and, along with local emergency 

responders, would be involved in oversight of the company’s response to a pipeline 

incident.

7.5 Industry Trends and Outlook

As previously stated, at least 65 natural gas pipeline projects, accounting for more than 12.3 

bcf/d, were completed in the United States in 1999 and 2000 – an increase of 15 percent from 

the level completed in 1998 (Energy Information Administration 2001a). 

Figure 7.4 shows annual additions to natural gas pipeline capacity from 1998 through 2002. 

Proposed capacity additions in 2002 are more than half those of 2000, and significantly more 

than any other year. Figure 7.5 shows the annual natural gas pipeline construction

expenditures for the same years. An estimated 5 billion dollars is expected to be spent in 2002, 

about one-half of which is in the Southeast.

Natural gas consumption is expected to continue to grow steadily with demand forecasted to 

reach at least 32 trillion cubic feet by 2025. Although rising demand by electricity generators 

accounts for 33 percent of the projected increase, growth is also expected in the residential, 

commercial, industrial, and transportation sectors. Natural gas consumption in the electricity 

generation sector is projected to grow steadily as demand for electricity increases and retiring 

nuclear and older oil and gas steam plants are replaced by newer, more efficient facilities. 

Natural gas consumption for electricity generation (excluding cogeneration) is projected to 

increase from 5.3 trillion cubic feet in 2001 to 10.6 trillion cubic feet in 2025 (Energy Information 

Administration 2003a).

Projected growth in natural gas consumption will require additional pipeline capacity. Expansion 

of interstate capacity will be needed to provide access to new supplies and to serve expanding 

markets. Expansion is projected to proceed at an average rate of 1.0 percent per year. The 

greatest increases in capacity are expected along the corridors that provide access to

Canadian, Gulf Coast, and Mountain region supplies and deliver them to the South Atlantic, 

Pacific, and Northeast regions. In all regions, growth in new pipeline construction is expected to 

be tempered by higher utilization of existing pipeline capacity (Energy Information

Administration 2003a).

It is estimated that an investment of between $40 and $80 billion in new pipeline and expansion 

of current pipelines would need to occur. The Energy Information Administration reported that 

approximately $9.3 billion was spent in 2001, $4.4 billion was spent in 2002, and estimated $4.1 

billion to be expended in 2003 (Energy Information Administration 2003b).
113

Regional Trends – Southeast: Of the six regions in the U.S., the Southeast actually uses the 

least amount of natural gas compared to the overall energy mix – 14 percent versus the national 

average of 24 percent (Figure 7.6). However, between 1990 and 1997, natural gas use for 

electric power generation increased at an annual rate of 8.5 percent. Since 1990, the region 

has also shown substantial growth in the industrial sector overall, with natural gas usage

increasing at an annual rate of 3 percent per year as the number of new industrial customers 

also grew (Energy Information Administration 1999).

0 2,000 4,000 6,000 8,000 10,000 12,000 14,000

US Total

Western

Southwest

Southeast

Northeast

Midwest

Central

(Mcf)

2002 - Proposed

2001 - Scheduled

2000

1999

1998

Figure 7.4. Annual Additions to Natural Gas Pipeline Capacity by Region.

Source: Energy Information Administration (2001a)

0 1,000 2,000 3,000 4,000 5,000 6,000

US Total

Western

Southwest

Southeast

Northeast

Midwest

Central

(Million Dollars)

2002 - Proposed

2001 - Scheduled

2000

1999

1998

Figure 7.5. Annual Natural Gas Pipeline Construction Expenditures by Region.

Source: Energy Information Administration (2001a) 
114

Between 1990 and 2000, pipeline capacity into the Southeast Region grew by 10 percent. A 

significant amount of the volume flows through this region and into markets in the Northeast and 

Midwest. Use of available interstate pipeline capacity during peak demand periods is high in 

most states in the region. Nevertheless, enough additional capacity is expected to be installed 

in the next few years to preclude any major capacity shortfall. Nine natural gas pipeline 

expansions have already been completed in the Southeast Region to improve deliverability 

within the region – primarily in North and South Carolina, Georgia and Alabama. Approximately 

1.9 bcf/d of additional capacity was also added in the region in 1999-2000. This included 

enhancement of the Columbia Gulf Transmission system and completion of several

Transcontinental system projects that totaled 863 MMcf/d of added system capacity. The

Transcontinental projects included completion of the Cardinal intrastate pipeline and Pine

Needle LNG link in North Carolina, and the southern most expansion of Transcontinental’s 

mainline in Alabama and Georgia.36

Other proposed projects within the region include expansion of pipeline access to underground 

storage sites that are also expanding, development of new capacity on intrastate pipelines to 

improve service to expanding end-use markets, and installation of new interstate capacity that 

will complement these intrastate expansions. For instance, Southern Natural Gas, East

Tennessee Gas, and Transcontinental Gas Pipeline companies will increase their existing 

system capacity in the region by up to 200 MMcf/d each within the next two years. Most of this

capacity will either provide direct delivery to end users, such as new gas-fired power plants, or 

increase deliveries to expanding intrastate systems such as the Sandhills Pipeline (300 MMcf/d) 

built in North Carolina in 2001. 

 

36 Unless otherwise noted, text in this subsection is from: Energy Information Administration, Natural 

Gas Transportation – Infrastructure Issues and Operational Trends, (Washington D.C.: Department of 

Energy), October 2001, p. 14-15.

23

20

40

12

18

24

21

24

20

39

14

21

25

23

0

5

10

15

20

25

30

35

40

45

Total Western Southwest Southeast Northeast Midwest Central

1990

1997

Figure 7.6. Percent of Total Energy Fueled by Natural Gas in the United States.

Source: Energy Information Administration (1999a) 
115

The increasing importance of access by shippers and other pipeline customers to the highdeliverability underground storage located in the region is exemplified by the several pipeline 

expansion projects that are predicated upon expected expansions of existing storage facilities 

currently interconnected to the pipelines:

• In conjunction with the approved 2002 Petal Gas Storage site expansion, for

example, its operator has proposed building a 59-mile, 36-inch, 680 MMcf/d capacity 

pipeline from that storage facility to new interconnections with Transcontinental Gas, 

Southern Natural Gas, and Destin Pipeline companies.

• Another storage facility that is expected to be expanded is the Bay Gas McIntosh 

facility in Alabama. Its operators will build an additional 18-mile pipeline from the site 

to provide shippers a new interconnection with Gulf South Pipeline Company.

GulfStream Natural Gas Project: The most significant pipeline development in the region is the 

construction of the 1,130 MMcf/d Gulfstream Pipeline. Placed into service in May 2002, the 

Gulfstream Natural Gas Project is a 753-mile pipeline that originates near Pascagoula,

Mississippi and Mobile, Alabama, crosses the Gulf of Mexico (with 431 miles of 36-inch 

diameter pipe) to Manatee County, Florida (Figure 7.7). Onshore, 306 miles of pipe, ranging in 

diameter from 36 inches to 16 inches, stretches across south and central Florida, terminating in 

Palm Beach County. The pipeline provides approximately 1.1 bcf per day of natural gas to fuel 

new electric generation capacity throughout Florida. 

Gulfstream has precedent agreements with 10 large Florida utilities and power generation 

facilities which represent long-term commitments for the majority of its 1.1 bcf per day. 

Figure 7.7. Gulfstream Natural Gas Project.

Source: Natural Gas System, L.L.C. (2002) 
116

Subsidiaries of Duke Energy and Williams purchased 100 percent interest in the Gulfstream 

Project from Coastal Corporation in February 2001.37 

Completion of the Gulfstream Pipeline means that the Florida Gas Transmission Pipeline is no 

longer the only source of gas available to the state’s natural gas shippers and customers. 

Nevertheless, the Florida Gas Transmission Company still continues to expand its system. In 

2001, it completed a 200-MMcf/d expansion and expects to add another 200 MMcf/d in 2002 

with completion of its Phase V expansion.

Regional Trends – Southwest: The rate of capacity growth in the Southwest Region has been 

decreasing – reflecting the maturity and the large amount of pipeline capacity already in place 

that is directed out of the Southwest. This downward trend also reflects the increase in

resources within the region, as rising consumer demand competes for available natural gas 

supplies. Even so, the natural gas pipeline systems exiting these producing states, for the most 

part, still maintain high utilization rates, and the region itself still remains the principal supplier of 

natural gas to the rest of the nation (Figure 7.2).

38

 

Among the few areas of the Southwest Region where natural gas production is growing is in the 

Gulf of Mexico, specifically in the central portion of the Gulf. According to a study published by 

the Gas Research Institute, “offshore Gulf of Mexico is the only area of the U.S. that offers 

potential new gas supplies for gatherers/processors. This is also the only region where any 

significant exploration is occurring.” Extensive development of deepwater leases in particular 

has increased natural gas production offshore of Louisiana, Mississippi, and Alabama by 10 

percent since 1995. Much of this increased production has come from new platforms that have 

had to be serviced by new gathering pipeline and/or large capacity pipelines designed to 

transport this production onshore. Between 1997 and 2000, for instance, 22 natural gas 

pipeline projects were completed that added a total of 8.2 bcf/d of new pipeline capacity in the 

Gulf. The largest three new pipelines to onshore Louisiana were: 

• Destin Pipeline – With a capacity of one bcf/day, 67 percent of the Destin Pipeline is 

owned by BP-Amoco and 33 percent by Shell Destin, LLC. This 255-mile pipeline 

started transporting natural gas in September 1998. It extends from Viosca Knoll 

Block 900 to Main Pass Block 260 then north to a processing plant operated by BPAmoco at Pascagoula, MS, and then extends north to interconnections with five 

major interstate gas pipelines.

• Nautilus Pipeline – With a capacity of 600 MMcf/d, the Nautilus Pipeline is owned 50 

percent by Shell Gas Transmission, LLC, and approximately 25 percent each by 

Marathon and Leviathan. It is 101 mile in length, 33 inch diameter, and started 

transporting in December 1997. It extends from Ship Shoal Block 207 to onshore 

Louisiana interconnects with 4 interstate and 3 intrastate pipelines, and straddles the 

existing Exxon Garden City Gas Plant and the Neptune Gas Plant, which became 

operational in late February 2000.

 

37 Due to regulatory mandates related to Coastal Corporation’s merger with El Paso Energy

Corporation, Coastal was forced by FERC to divest the project. 

38 Unless otherwise noted, figures and text in this subsection is from Energy Information 

Administration, Natural Gas Transportation – Infrastructure Issues and Operational Trends, (Washington 

D.C.: Department of Energy), October 2001, p. 10.
117

• Discovery Pipeline – Currently owned by Texaco and Williams, it serves as a main 

line extending from a platform in Ewing Bank Block 873, on the edge of the 

deepwater province, to a processing plant near Larose, LA and a fractionator near 

Paradis, LA. The 105 miles of 30 inch pipe has a capacity of 600 MMcf/d.

Almost all (98 percent) of the 1.7 bcf/d of new natural gas pipeline capacity scheduled to be 

developed and placed in service in the Gulf consists of new gathering pipelines. The largest of 

these, in capacity, will be the 500 MMcf/d Canyon Express system. The Canyon Express 

Pipeline System, operated by TotalFinaElf, S.A. is the deepest pipeline ever. The 55-mile, dual 

12-inch line is being laid in more than 7,000 feet of water to connect the Kings Peak,

Aconcagua, and Camden Hills deepwater gas fields on Mississippi Canyon to the Canyon

Station platform on East Main Pass 261. The three fields are located about 120 miles southeast 

of New Orleans in water depths ranging from 6,700 to 7,300 feet – setting a new record for 

commercial production water depths. The lines completed in 2002 are able to move 500 MMcfd 

of gas to the platform, which was installed second quarter 2002 (Oil and Gas Journal 2002, Gas 

Daily 2000). 

Elsewhere in the Southwest Region, the level of proposed pipeline capacity expansion is 

minimal. While five of the seven remaining pipeline projects scheduled for 2001-2002 address 

the needs of shippers and producers to gain additional access to the few onshore areas in the 

region that are experiencing production expansion, the level of potential added capacity of these 

projects is less than 0.5 bcf/d. Furthermore, the region’s largest onshore pipeline project 

scheduled in the next 2 years represents only 427 MMcf/d of capacity to transport natural gas 

from Louisiana to supply a 2,700 megawatt power plant located in southern Arkansas. Overall, 

the potential additional capacity currently slated for the Southwest Region in 2001 and 2002 

totals only about 3.0 bcf/d. This is the smallest amount of planned capacity additions of the six 

regions.

Corporate Realignments: Over the past 15 years, a number of regulatory and market

changes have greatly affected the operations and structure of the natural gas transmission 

industry (Figure 7.8). “While the Order 636 had the effect of reducing pipeline revenues 

(although not necessarily profitability) because interstate pipelines no longer were sellers of 

natural gas, the revised rate design allowed them to collect most of their costs in fixed demand 

charges, which reduced the risk of recovering these costs. Order 636 also established a

release (reseller) market for transportation and storage capacity, which provided a mechanism 

for the marketing of unused or underutilized pipeline capacity” (Energy Information

Administration 1999a). This industry restructuring encouraged pipeline companies to revise 

their strategies, which may account for the increased level of mergers and acquisitions in recent 

years.

There have been some very large consolidations of pipeline assets under single corporate 

umbrellas. The corporate strategies behind these moves have varied, but the outcomes have 

been profound. For instance, when gas pipeline companies were no longer permitted to engage 

in the sale of natural gas, many companies created affiliated natural gas marketing arms or 

subsidiaries and transferred the merchant functions to these new divisions. Today, many of 

these marketing entities also engage in the marketing of other types of energy as well (Energy 

Information Administration 2001a).
118

Mergers and Acquisitions: Driven by rapidly changing conditions in traditionally regulated 

markets, energy companies are under tremendous pressure to execute successful new

business strategies to survive and prosper. Mergers, acquisitions and joint ventures are

important tools that can be used to take advantage of opportunities and withstand the

challenges presented in a changing industry. “The recent trend toward industry consolidation is 

changing this loose configuration of companies as producers, gathering companies, marketers 

and LDCs all jockey for position, while many seek to take advantage of structural changes in the 

industry, and some struggle simply to survive” (Energy Information Administration 1999a).

The largest instance of consolidation has been carried out by the El Paso Energy Corporation. 

Once the owner of only one major pipeline, since 1997, it has acquired eight other interstate 

pipelines systems (Table 7.4). The original gas sales and marketing arm of the El Paso Natural 

Gas Pipeline became El Paso Merchant Energy Company, one of the top 10 natural gas and 

energy marketing companies in the U.S. in 2000.39 

 

39 The remainder of this subsection is taken from: Energy Information Administration, Natural Gas 

Transportation – Infrastructure Issues and Operational Trends, (Washington D.C.: Department of Energy), 

October 2001, p. 17-18.

Prior to FERC Order 636

Parent Company

Pipeline “A”

Pipeline “B”

Prior to FERC Order 636

Parent Company

Pipeline Transportation

Pipeline “A”

Storage Services

Pipeline “B”

Production

(Exploration/Development)

Marketing

(Buying/Selling Gas)

Market Center Services*

(New)

Formed into separate corporate

divisions, affiliates, or sold off.

Some pipeline companies still retain

production field assets.

Toward Formation of

Total Energy Business

Electric Utility and Oil

Resources Segments

Energy Marketing Services Transportation Services

 Transportation Services

 Storage Operations

 Production

 Purchasing

 Selling

 Buying

 Selling

 Trading

Figure 7.8. Corporate Realignments.

Source: Energy Information Administration (1999b) 
119

Table 7.4

Shifts in Ownership of Selected Major Interstate Natural Gas Pipeline Companies since 1990

Parent / Pipeline Name Marketer Affiliate / 

Prior Ownership

Merger 

Year

Market Area 

Served

System 

Mileage

System 

Capacity 

(MMcf/d)

CMS Energy Corp CMS-MST

 Panhandle Eastern Pipeline Co Panhandle Eastern Corp 2000 Midwest 6,467 2,765

 Sea Robin Pipeline Co SONAT Corp 2000 Gulf Coast 470 1,241

 Trunkline Gas Co Panhandle Eastern Corp 2000 Midwest 4,134 1,884

Duke Energy Corp Duke Energy Trading Co

 Algonquin Gas Transmission Co Panhandle Eastern Corp 1999 Northeast 1,092 1,586

 East Tennessee Natural Gas Co Tenneco Energy Corp 2000 Southeast 1,100 700

 Maritimes & Northeast PL Co Built in 1999 n/a Northeast 304 440

 Texas Eastern Transmission Corp Panhandle Eastern Corp 1999 Northeast 12,100 5,939

El Paso Corp El Paso Merchant Energy

 ANR Pipeline Co Coastal Corp 2000 Midwest 9,553 5,846

 Colorado Interstate Gas Co Coastal Corp 2000 Central/Denver 4,123 2,350

 El Paso Natural Gas Co El Paso Energy Co n/a Western/Southwest 10,009 5,344

 Mojave Pipeline Co Built in 1993 n/a Western 362 550

 Portland Gas Transmission Co Built in 1993 n/a Northeast 242 178

 South Georgia Natural Gas Co SONAT Corp 1999 Southeast 909 129

 Southern Natural Gas Co SONAT Corp 1999 Southeast 7,612 2,536

 Tennessee Gas Pipeline Co Tenneco Energy Corp 1999 Northeast 9,270 5,587

 Wyoming Interstate Gas Co Coastal Corp 2000 Central 425 1,175

Enron Corp ENRON Online Trading

 Florida Gas Trans Co No Change n/a Southeast 5,203 1,405

 Northern Natural Gas Co No Change n/a Midwest 15,637 3,800

 Transwestern Gas Co No Change n/a Western 2,532 2,700

Kinder-Morgan Corp KM Gas Services Division

 Kinder-Morgan Interstate PL Co KN Energy Corp 1999 Central 6,081 1,075

 Kinder-Morgan Texas PL Co MidCon Corp 1999 Southwest (TX) 2,101 na

 Natural Gas Pipeline Co of America MidCon Corp 1998 Midwest 10,076 5,001

 Trailblazer Pipeline Co MidCon Corp 1998 Central/Midwest 436 605

Koch Corp Koch Energy Trading Co

 Gulf South Pipeline Co United Gas Corp n/a Southeast 7,252 3,476

 Mobile Bay Pipeline Co Built in 1993 1998 Southeast 26 600

Leviathan Gas Pipeline Partners

 High Island Offshore System KN Energy Corp 2000 Gulf Coast 247 1,800

 UT Offshore System KN Energy Corp 2000 Gulf Coast 30 1,040

NiSource Corp

 Columbia Gas Transmission Corp Columbia Energy Corp 2000 Northeast 11,215 7,276

 Columbia Gulf Transmission Co Columbia Energy Corp 2000 Southwest/Northeast 4,200 2,317

 Crossroads Pipeline Co Built in 1995 n/a Midwest 205 250

 Granite States Gas Trans Co Northern Utilities Inc. 1999 Northeast na na

Northern Border Partners

 Midwestern Gas Transmission Co Tenneco Energy Corp 2001 Midwest 350 785

 Northern Border Pipeline Co No Change n/a Midwest 1,214 2,355

Reliant Energy Corp Reliant Energy Wholesale

Group

 Mississippi River Trans Co No Change n/a Midwest/Central 1,976 1,670

 Reliant Energy Gas Trans Co No Change n/a Southwest 6,228 2,797

Williams Companies, Inc Williams Energy Services

 Cove Point LNG LP Columbia Energy Group 2001 Northeast 87 585

 Kern River Transmission Co Built in 1992 n/a Western 922 800

 Northwest Pipeline Co No Change n/a Western 3,932 2,900

 Transcontinental Gas Pipeline Co Transco Energy Corp 1997 Northeast 10,562 7,000

 Williams Gas Pipeline - Central No Change n/a Midwest 5,926 2,800

 Williams Gas Pipeline -

SouthCentral

Transco Energy Corp 1997 Central 5,573 2,000

Xcel Corp

 Viking Gas Transmission Co Northern States Power Co 2000 Midwest 662 516

Source: Energy Information Administration (2001a) 
120

Similarly, the Williams Company also succeeded in creating a nationwide pipeline network 

through the acquisition of other pipeline companies. These pipelines include: Kern River 

Transmission, Northwest Pipeline, and Transcontinental Gas Pipeline. Its natural gas marketing 

and trading arm, Williams Energy Services Inc., ranked about 18th in the United States in 2000, 

based on contracted volume.

The Duke Energy Corporation, a regional (Southeast) electric power company at the start of the 

1990's, began acquiring interstate pipeline companies in the mid-1990's. Its original objective 

appears to have been the development of a nationwide pipeline network of affiliates. But in 

1997 the company changed course and sold those interstate pipeline company affiliates that did 

not serve its historic southeastern marketplace or the eastern United States. It retained the 

natural gas marketing expertise from its original acquisitions. Duke Energy Marketing has grown 

substantially and was the second-largest natural gas marketer (by volume) in the United States 

in 1999 and 2000.

Similar to Duke Energy Corporation, CMS Energy Corporation was a regional (Midwest) energy 

company that did not own any interstate pipeline companies before 1993. When it did enter the 

interstate pipeline market, it did so by buying the several pipelines that Duke Energy divested 

itself of in the Midwest. Today, CMS has integrated these interstate pipeline companies into its 

regional (Midwest-Southwest) energy marketing operations. Its CMS-MST (Marketing, Services 

and Trading) subsidiary ranked among the top 20 natural gas marketers in 2000. 

Kinder-Morgan Corporation is a relative newcomer to the interstate pipeline community. In 1998 

it acquired the Mid-Con Corporation and its two interstate pipelines. In 1999, it acquired the KN 

Energy Company with its one wholly owned system and one joint-venture pipeline

(TransColorado Gas Transmission Co). Nevertheless, even with these acquisitions, it still

remains focused on markets in the mid-continent region of the United States. While it has a 

natural gas marketing arm (KM Gas Services Division), its operations are primarily confined to 

services within its regional service area.

Oil Pipelines: The total amount of crude and petroleum products transported in 2001 totaled 

869.8 billion ton-miles – 66 percent of which was transported by pipelines. For crude oil only 

transport, pipelines carried almost 74 percent of the total 376.6 billion ton-miles transported in 

the U.S. This represented a decrease of 0.2 percent from 2000, however, there was an overall 

decrease of 0.4 percent in total ton-mile movements for all modes of transportation during the 

same period. Pipeline transport of crude and petroleum products however, has increased over 

the last 20 years (Association of Oil Pipelines 2003b). Figure 7.9 shows that petroleum 

transported by pipeline – as a total of all modes of transportation – has increased by 43 percent 

since 2001. This reflects an average annual increase of almost 2 percent per year. 
121

With the increase in production from the deepwater areas of the Gulf, an extensive underwater 

pipeline network has formed. By 2001, 7,835 miles of pipe had been laid in the Gulf (in both 

shallow and deep water) – 4,121 miles of which are in deepwater with more projects underway. 

One such project is the Mardi Gras transportation system which, when completed, will be the 

largest-capacity deepwater pipeline system ever built; capable of transporting more than one

million barrels per day of oil and 1.5 billion cubic feet of gas. The system, being developed by 

BP America and partners, will consist of five pipelines, three of which are oil pipelines (Oil and 

Gas Journal 2003):

• The Caesar Oil Pipeline – capacity of 450,000 b/d;

• The Proteus Oil Pipeline – capacity of 420,000 b/d; and

• The Endymion Oil Pipeline – capacity of 420,000 b/d.

In the Green Canyon area, BP and partners BHP Billiton Petroleum, Shell Pipeline Co. LP, and 

Union Oil Co. of California formed Caesar Oil Pipeline Co. LLC to undertake construction of the 

Caesar pipeline. This 450,000 b/d line will consist of a 28-inch mainline and 24-inch laterals to 

the Holstein and Mad Dog spars and the Atlantis semi-submersible platform. It is due online in 

2004. 

In Mississippi Canyon, BP and ExxonMobil Pipeline Co. formed Proteus Oil Pipeline Co. LLC to 

build the Proteus pipeline from the Thunder Horse semisubmersible platform to a new-build 

platform, to be installed on South Pass Block 89E in about 400 ft of water. The platform will 

0%

10%

20%

30%

40%

50%

60%

70%

80%

1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001

(percent of total transport)

Figure 7.9. Total Crude Petroleum and Petroleum Products Carried by Pipelines as a Percent 

of Total Petroleum Transported.

Source: Association of Oil Pipelines (2003b) 
122

enable tie-in of shelf discoveries in the area, as well as the future installation of 50,000-hp 

pumps to increase pipeline capacity, when needed. This 28-inch high-pressure line will have an 

installed capacity of 420,000 bbl/d, expandable to 580,000 bbl/d. 

The related 30-inch Endymion pipeline -- undertaken by another BP-ExxonMobil Pipeline Co. 

entity, Endymion Oil Pipeline Co. LLC -- will have a capacity of 420,000 bbl/d, expandable with 

booster pumps to 750,000 bbl/d. The oil will be transported from South Pass 89E to landfall at 

Grand Isle, then on to the LOOP facilities.

Oil shipped in the Proteus and Endymion lines will have access to southern Louisiana area 

refineries, via pipelines, including LOCAP LLC's line from Clovelly to St. James, LA; the

Clovelly-Alliance-Meraux line; and Shell Oil Pipeline to Norco, LA, and Texas. Both pipelines are 

due on line in 2005 (Oil and Gas Journal 2003).
123

8.0 PIPE COATING FACILITIES

8.1 Introduction

Pipelines that transport oil and gas are coated on the exterior to protect against corrosion and 

other damage. Pipes may also be coated on the inside to protect against corrosion from the 

fluids being transported or to improve the flow. In addition to corrosion protection, pipes that will 

be used offshore are also coated with a layer of concrete to increase the weight of the line to 

ensure it will stay on the seabed. 

Among the many threats to pipeline integrity are third-party damage, geological activity and 

corrosion. The most common threat, external corrosion, is recognized as the main deterioration 

mechanism that can reduce the structural integrity of buried pipelines. In fact, corrosion ranks 

only second to human error as a cause of pipeline failure (Taylor 1994). Because coatings are 

the first line of defense in protecting pipelines against corrosion, they must be well bonded, 

continuous and resist the effects of their environments. “The application of corrosion-protective 

coatings to pipelines has emerged as an industry because of economics. It is a cost-effective 

means of extending the life of a pipeline. It is the economics of the coatings system as well as 

its performance which justifies the industry” (McConkey 1982).

To be effective, pipeline coating must satisfy several properties (Kennedy 1993):

• easy to apply

• adheres well to pipe

• resists impact

• is flexible

• resists soil stress

• resists flow (of coating)

• is resistant to water

• is resistant to electricity

• is chemically and structurally stable

• resists bacteria, marine organisms, and cathodic disbondment.

8.2 Description and Typical Facilities

Pipeline construction methods differ depending on the geographical area, the terrain, the 

environment, the type of pipeline, and the restrictions and standards imposed by governments 

and regulatory agencies. The biggest differences exist between land construction and offshore 

construction; however, all pipeline construction projects have a number of features in common

(Kennedy 1993):
124

• The methods of designing the system – arriving at the optimum pipe diameter, 

determining the amount of horsepower required for pumping or compression,

meeting safety standards – are similar for all pipelines.

• There are a number of design criteria that are set by government or regulatory 

agencies to insure safe operation of a pipeline and the safety of personnel and 

property near the pipeline. These standards vary depending on the location of the 

pipeline, both geographically and in relation to populated areas and other facilities.

• Comprehensive environmental impact studies are required in many countries before 

construction permits can be issued. Construction plans must provide for the

protection of scenery, wildlife, archeological sites, and other historic assets.

• Most oil, gas, and products pipelines are constructed by welding short lengths, or 

joints, of pipe together. There are a few exceptions to the use of welded

connections, but these are in short lines within a producing field or in similar

applications. 

• Extensive testing of welders and the welds they produce is an important part of the 

construction of all long-distance petroleum pipelines.

• Almost all oil and gas pipelines are buried below ground level, even most offshore 

pipelines are buried below the sea bed for protection. There are cases in which 

large segments of a major pipeline are not buried, the most notable example of 

which is the trans-Alaska crude pipeline where above ground sections were installed 

to protect permafrost areas.

• All pipelines are tested for leaks following construction before the line is put in 

service. Several techniques can be used, but the most common is hydrostatic 

testing – filling the line with water and subjecting it to a pressure greater than the 

design operating pressure.

• Most pipelines are coated on the exterior to prevent corrosion. Offshore pipelines 

are also “weight-coated” with a concrete coating to overcome the force of buoyancy 

and to prevent the pipe from floating to the surface.

• Most pipelines must have one or more pumping stations or compressor stations 

along the route to provide energy to overcome pressure loss and keep the fluid in the 

pipeline moving.

• The construction of all pipelines follows this general sequence: design and route 

selection, obtaining rights of way, installation, tie-in to origin and destination facilities 

and pumping or compressor stations, and testing.

Corrosion: Corrosion is an electrochemical process involving an area of higher potential – the 

anode (a piece of metal that readily gives up electrons); and an area of lower potential – the 

cathode (a piece of metal that readily accepts electrons). The electrolyte is a liquid or some 

conveyor that helps the electrons move from the anode to the cathode. The anode will become 

corroded, while the cathode will not be subject to damage. When a piece of metal corrodes, the 
125

electrolyte helps provide oxygen to the anode. As oxygen combines with the metal, electrons 

are liberated. When they flow through the electrolyte to the cathode, the metal of the anode 

disappears, swept away by the electrical flow or converted into metal cations in a form such as 

rust. In the case of a buried pipeline, the soil is the electrolyte. These areas of different 

potential exist along a pipeline. The magnitude of the potential difference depends on soil 

conditions, among other factors. 

The electrical potential between the anode and cathode is what causes the corrosion current to 

flow (Allied Corrosion Industries, Inc. 1998). The anode is the area that is subject to corrosion 

and the severity of which is directly proportional to the amount of current flow. There are many 

types of corrosion. Some common industry types include (Allied Corrosion Industries, Inc. 

1998): 

• Dissimilar metal corrosion (or galvanic corrosion): Occurs when two metals with

different compositions are metallically contacting each other in a common current 

flow. The negative potential composition of each metal determines which metal acts 

as the anode and the rate of corrosion.

• Differential aeration corrosion: Occurs when part of the pipe is exposed to wellaerated soil (cathode region) and the other part exposed to a poor supply of oxygen.

• Corrosion can also occur when new sections are used and welded with old sections 

in repairs and additions. “The unfortunate thing about this type of corrosion is that the 

newer structure will normally become the anode.”

Cathodic Protection: Cathodic protection refers to the method of preventing corrosion in metal 

structures that involves using electric voltage to slow or prevent corrosion. It is used along 

natural gas pipelines, as well as in certain bridges or other large metal structures that need to 

resist corrosion over an extended period of time. 

In a cathodic protection system, anodes are installed and an electrical current is made to flow 

between the pipe and the anodes through the soil. The pipeline becomes the cathode of the 

system, and corrosion is decreased. The anodes, the part of the system that is corroded, are 

“sacrificed.”

Cathodic protection eliminates anodic areas on an underground metallic structure. With the 

implementation of cathodic protection, constant surveying of how the protection is holding up, 

whether it is disbondment of the coating or if new coating faults arise, is a significant

implementation that has arisen in the industry. During pipeline fabrication, all possible

measures are taken to detect and repair coating faults.

It is possible to calculate the electrical resistance of a coated pipeline, given the coating 

specifications and pipeline dimensions, but it is impossible to calculate the actual resistance of 

the total pipeline over time with varied external conditions affecting the structure. The 

magnitude of the corrosion currents for a given potential difference between two electrodes 

(cathode and anode) depends on several factors (Kennedy 1993):
126

• Soil resistivity - This is determined by temperature, moisture content, and the 

concentration of ionized salts present. Generally, corrosion is high in low-resistivity 

soils and can be low in high-resistivity soils.

• Chemical constituents of the soil - The type of salts in the soil affect the rate of 

corrosion.

• Separation between anode and cathode - Corrosion is more likely to occur when the 

anode and cathode are close together. Increasing the distance between two

dissimilar metals (electrodes) reduces corrosion current intensity.

• Anode and cathode polarization - Protective films formed at the anode and cathode 

affect corrosion rate.

• Relative surface areas of cathode and anode - For a given magnitude of corrosion 

current, the depth of corrosion on the anode will be inversely proportional to anode 

area.

External Corrosion Coating: Pipeline coating inhibits the flow of electric current from the pipe 

and the resulting loss of steel. Once the coating is applied, tape is wrapped around the pipe in 

a spiral pattern with the edges overlapping slightly so that all of the pipe coating is covered. 

Wrapping tape, normally either a heavy paper or plastic, protects the coating from damage. 

The earliest anti-corrosion coatings for buried pipelines were bitumen-type coatings – asphalt 

mastic and enamel and coal tar enamel. However, over time, it has been found that these types 

of coating are subject to cracking, leading to contact of water with the pipe and coating 

disbondment. The asphalt coatings were also found to absorb water to a greater degree than 

other coatings. Developments in epoxy based adhesives have led to more desirable coatings 

such as fusion-bonded epoxy, polyethylene and polypropylene. Traditional pipeline anticorrosion coatings are being progressively replaced by complex multi-layer composite systems. 

These new coatings start with a fusion-bonded epoxy layer, combined with a robust shield of 

thick extruded polyethylene or polypropylene. 

“The ability of a coating system to perform as a corrosion barrier depends upon the resistance 

to damage exhibited by the coating as well as its inherent corrosion-protective properties as 

determined by adhesion to the steel and resistance to the corrosive environment. This ability is 

a function of the properties of the coating material combined with the coating process which 

produces the coating system. The coating process must be capable of applying the coating in 

such a manner as to achieve the final performance properties of the material” (McConkey 

1982). Table 8.1 is a comparison of the advantages and disadvantages of different types of 

coatings systems used on pipelines today. 
127

Fusion-Bonded Epoxy: One of the most popular coatings used today is the fusion-bonded 

epoxy. The use of fusion-bonded epoxy pipe coatings began to expand in the early 1980s, and 

they are considered to offer a number of advantages. “The high-temperature performance, 

chemical resistance, resistance to soil stress, and excellent resistance to cathodic disbondment 

in comparison to traditional coatings has led to the increased use of fusion-bonded epoxy. 

Fusion-bonded epoxy coatings have become more attractive due to several advances in both 

the application process and in the raw material” (McConkey 1982). Fusion-bonded epoxy 

coatings provide a more controllable application process and a product whose quality can be 

assured before the laying of the pipeline. 

Table 8.1

Comparison of Pipeline Coating Systems Currently Used

Advantages Disadvantages

Asphalt/Coal tar: 1940 to 1970

- Easy to apply - Subject to oxidation and cracking

- Minimal surface preparation required - Soil stress has been an issue

- Long track record in certain environments w/o failure - Limitations at low application temps

- Permeable to cathodic protection in event of failure - Environmental and exposure concerns

- Associated with corrosion and stress 

crack corrosion failures

Tape wrap (two layer): 1960 to present

- Simple application - Poor shear stress resistance

- Many documented failures related to 

corrosion and stress crack corrosion

- Shielding of cathodic protection

- Adhesives subject to biodegradation

Two-layer extruded polyethylene: 1960 to present

- Excellent track record - Limited temperature range

- Good handling - Poor shear stress resistance

- Limited pipe sizes (<24 in. outside 

diameter)

Fusion-bonded epoxy: 1975 to now

- Excellent adhesion and corrosion resistance - Low impact resistance

- Does not shield cathodic protection

- High moisture absorption and 

permeation

Three-layer polyolefin: 1986 to present

- Excellent combination of properties

- Best suited for electrical resistance 

welded pipes

- High thickness to eliminate weld 

tenting

Composite coating: 1990 to present

- Excellent combination of properties

- Suitable only for large diameter pipes 

and is not designed for small diameter 

pipes

- Conforms well to external raised well profiles

Source: CorrosionSource (2002) 
128

Concrete Coating for Offshore Pipe: Offshore pipelines are coated with concrete in addition 

to the corrosion coating to provide negative buoyancy (a weight greater than the buoyant force 

of the water) to the pipeline. This added weight is necessary to cause the pipeline to sink to the 

ocean floor and remain in position on the seabed. To be effective, a concrete coating must 

resist damage during installation and after it is in place. In addition to providing needed weight, 

the concrete coating protects the corrosion coating. 

There are three major requirements of concrete coating in maintaining the stability of pipeline on 

the seabed (Kiernan 1982):

• Negative buoyancy – Originally, the chief function of negative buoyancy was to add 

sufficient weight to the pipeline to achieve the required negative buoyancy, hence the 

term “weight coating.” This primary function has not changed over the years since 

the first offshore lines were laid in the Gulf in the late 1940s. However, experience 

has proven that weight coating must meet additional requirements as follows.

• Resistance to damage – To remain in position during pipeline life, a concrete 

coating must have resistance to damage during laying and trenching operations, 

from natural environmental hazards during the life of the pipeline at the bottom of the 

sea, and from the effects of human hazards such as fishing trawls and trailing cables 

from floating vessels.

• Protection of anticorrosion coating – Presently used techniques of anticorrosion 

coating are subjected to damage when exposed to trawl gear or trailing cables. 

Design of the concrete coating is critical if it is to withstand laying stresses and resist damage 

from anchors, fishing gear, and other hazards during operation. Considerable research has 

been aimed at the improvement of concrete coatings and application methods, based in part on 

the performance of early concrete-coated pipelines. One of the most critical considerations in 

concrete coating design is the overbend area where the pipe leaves the lay barge’s pipe ramp 

during installation. If laying stresses are not properly calculated and maintained within design 

limits, concrete coating can crack during installation (Kennedy 1993).

8.3 Industry Characteristics

Pipeline corrosion coating can be applied either before the pipe is delivered (yard applied) or 

after the pipe lengths are welded together and suspended above the trench. When pipe lengths 

are coated and wrapped at a coating yard before being delivered to the job site, a short distance 

at each end of each length of pipe is left bare so the joints can be welded together. When field 

welding is complete, coating and wrapping material is applied to the bare pipe sections. 

When all coating and wrapping is done at the job site, individual lengths are first welded

together and the pipeline is suspended over the trench. Special machines then move along the 

pipeline and apply coating to the entire pipe, welds and all. Tape is wrapped over the coating 

by a tape machine in a spiral. The wrapping machine maintains tension on the tape so it is 

fitted tightly over the coating (Kennedy 1993).
129

Application of Fusion-Bonded Epoxies: The process of applying fusion-bonded epoxy 

coating to pipelines involves four major steps: surface preparation, heating, powder application, 

and curing (Figure 8.1). Proper surface preparation assures that maximum adhesion will

develop at the interface between the pipe and the coating. The steel is blast-cleaned to a near 

white metal finish using abrasive grit – cleaning the pipe of contaminants, mill scale and rust. It 

also roughens the surface to give it a textured profile – texturing the surface also facilitates 

adhesion by increasing the exposed surface area of the steel and by providing more opportunity 

for the coating to chemically bond. After blast-cleaning, the steel is heated to approximately 450 

degrees F using electrical induction heaters. 

The heated pipes are then passed through a powder spray booth where dry epoxy powder is 

emitted from a number of spray nozzles. As the powder leaves the spray nozzle, an electrical 

charge is imparted to the particles. These electrically charged particles are attracted to the 

grounded steel surface providing an even coverage of the coating. When the dry powder hits 

the hot steel, it melts and flows into the textured profile and conforms to the ribs and

deformations of the pipe. The heat also initiates a chemical reaction that causes powder

molecules to form the complex cross-linked polymers that give the epoxy coating its beneficial 

properties. Following powder application, the coating is allowed to cure for a short period 

(approximately 30 seconds) during which it hardens. To facilitate handling, the curing period is 

often followed by an air or water quench that quickly reduces the bar temperature.

8.4 Regulations

Although not economically regulated like other segments of the natural gas industry, pipe 

coating techniques do have to meet industry specifications as established by the Department of 

Transportation and recommended by the National Association of Pipe Coating Applicators.40

 

40 The remainder of this section is taken from: 49 CFR 195, Parts 236-244 and 414-418, October 1, 

1999.

Figure 8.1. External/Internal Fusion Bonded Epoxy Coating Plant.

Source: Kennedy (1983) 

Incoming

pipe

inspection

External

power

application

Post

heat

Internal

powder

application

External

blast

clean

Quench

Final

inspection Preheat

Internal

blast

clean

Inspect /

grind

Heat

Incoming

pipe

inspection

External

power

application

Post

heat

Internal

powder

application

External

blast

clean

Quench

Final

inspection Preheat

Internal

blast

clean

Inspect /

grind

Heat
130

Part 195, under Title 49 (Transportation) of the Code of Federal Regulations is titled

“Transportation of Hazardous Liquids by Pipeline.” Section 195.238 lists the requirements for 

external coatings: 

• No pipeline system component may be buried or submerged unless that component 

has an external protective coating that: 

- Is designed to mitigate corrosion of the buried or submerged component;

- Has sufficient adhesion to the metal surface to prevent underfilm migration of 

moisture;

- Is sufficiently ductile to resist cracking;

- Has enough strength to resist damage due to handling and soil stress; and

- Supports any supplemental cathodic protection.

In addition, if an insulating-type coating is used, it must have low moisture absorption and 

provide high electrical resistance. All pipe coating must be inspected just prior to lowering the 

pipe into the trench or submerging the pipe, and any damage discovered must be repaired. 

Regulations for cathodic protection systems are also included in Section 195.242. A cathodic 

protection system must be installed for all buried or submerged facilities to mitigate corrosion 

that might result in structural failure. A test procedure must be developed to determine whether 

adequate cathodic protection has been achieved. A cathodic protection system must be

installed not later than one year after completing the construction. Except for offshore pipelines, 

electrical test leads used for corrosion control or electrolysis testing must be installed at

intervals frequent enough to obtain electrical measurements indicating the adequacy of the 

cathodic protection.

External Corrosion Control: According to the CFR, every pipeline operator must, at least 

once each calendar year, conduct tests on each buried, in contact with the ground, or

submerged pipeline facility in its pipeline system to determine whether the cathodic protection is 

adequate. In addition, pipeline operators must inspect each of its cathodic protection rectifiers 

on a bi-monthly basis. 

Once every five years, an operator must inspect the bare pipe in its pipeline system that is not 

cathodically protected and must study leak records for that pipe to determine if additional 

protection is needed. Whenever any buried pipe is exposed for any reason, the operator must 

examine the pipe for evidence of external corrosion. If any active corrosion is found, that the 

surface of the pipe is generally pitted, or that corrosion has caused a leak, further investigation 

must be undertaken to determine the extent of the corrosion.

Any pipe that is found to be generally corroded so that the remaining wall thickness is less than 

the minimum thickness required by the pipe specification tolerances must either be replaced 

with coated pipe that meets industry requirements or, if the area is small, must be repaired. 

However, the pipeline operator need not replace generally corroded pipe if the operating 

pressure is reduced to be commensurate with the limits on operating pressure, based on the 

actual remaining wall thickness.
131

If localized corrosion pitting is found to exist to a degree where leakage might result, the pipe 

must be replaced or repaired, or the operating pressure must be reduced commensurate with 

the strength of the pipe based on the actual remaining wall thickness in the pits.

Internal Corrosion Control: An operator may not transport any hazardous liquid or carbon 

dioxide that would corrode the pipe or other components of its pipeline system, unless it has 

investigated the corrosive effect of the hazardous liquid or carbon dioxide on the system and 

has taken adequate steps to mitigate corrosion. If corrosion inhibitors are used to mitigate 

internal corrosion the pipeline operator must use inhibitors in sufficient quantity to protect the 

entire part of the system that the inhibitors are designed to protect and shall also use coupons 

or other monitoring equipment to determine their effectiveness. Twice each calendar year, the 

monitoring equipment must be examined to determine the effectiveness of the inhibitors or the 

extent of any corrosion.

Whenever any pipe is removed from the pipeline for any reason, the operator must inspect the 

internal surface for evidence of corrosion. If the pipe is generally corroded such that the

remaining wall thickness is less than the minimum thickness required by the pipe specification 

tolerances, the operator shall investigate adjacent pipe to determine the extent of the corrosion. 

The corroded pipe must be replaced with pipe that meets industry requirements, or based on 

the actual remaining wall thickness, the operating pressure must be reduced to be

commensurate with the limits on operating pressure.

8.5 Industry Trends and Outlook

Based on an inventory conducted as part of the development of a GIS database for this project, 

16 pipe coating facilities that support the oil and gas industry were recorded within the Gulf 

region; 7 in Texas, 5 in Louisiana, 3 in Alabama, and 1 in Florida. As discussed in Chapter 7, 

with increases in natural gas demand, and promising developments in the Gulf of Mexico, 

transmission capacity will also need to expand, and thus the need for pipeline coating. In turn, 

pipeline coating companies have increased output to meet the increased demand for services. 

Chapter 3 previously outlined the new Bredero Price facility in Theodore, AL which replaced a 

smaller site in Harvey, Louisiana. Additionally, Bayou Companies in New Iberia, LA claims to 

have coated over 5,000 miles of pipe in the past year, up from an approximate 2,000 mile 

annual average for the five year period ending in 1999.41

Pipe coatings have evolved from simple coal-tar applications to more sophisticated fusionbonded epoxies and polypropylene coatings. Companies continue to try new methods and

materials, in the battle against corrosion and extreme environmental effects. 

One new product, recently introduced to the market is the Reilly Shrink Sleeves. The Reilly 

Pipeline Coating Group (PCG) is offering these sleeves that consist of a cross-linked polyolefin 

backing, a closure for mechanical protection and an anti-corrosive adhesive that will prevent 

corrosion at pipeline joints. Reilly PCG is working in concert with Fameim S.A. to produce the 

sleeves. The partnership will provide consumers with an end-to-end, single vendor solution for 

anti-corrosion pipeline coating products, as well as a high-quality joint coating for oil, gas, and 

water pipelines to provide total pipeline corrosion protection (Pipeline and Gas Journal Online, 

May 2002). 

 

41 The Bayou Companies website, http://www.bayoupipe.com/3-Proj-Fr.htm, (June15, 2002).
132

The increased activity in the Gulf should continue to push the development of new products and 

services that increase pipeline lives and repair. Companies with Gulf of Mexico facilities 

capable of accommodating large, deepwater projects stand to be great benefactors of the

current pipeline marketplace.
133

9.0 NATURAL GAS PROCESSING PLANTS

9.1 Introduction

Natural gas, as it is produced from a reservoir rock, is typically a mixture of light hydrocarbon 

gases, impurities and liquid hydrocarbons. Natural gas processing removes the impurities and 

separates the light hydrocarbon mixture into its useful components. Natural gas is found below 

the earth’s surface in three principal forms: 

• Associated gas is found in crude oil reservoirs, either dissolved in the crude oil, or 

combined with crude oil deposits. Associated gas is produced from oil wells along 

with the crude and is separated from the oil at the head of the well. 

• Non-associated gas is found in reservoirs separate from crude oil – its production is 

not a result of the production of crude oil. It is commonly called "gas-well gas" or 

"dry gas." Today about 75% of all U.S. natural gas produced is non-associated gas

(Natural Gas Information and Educational Resources 1998c).

• Gas Condensate is a hydrocarbon that is neither true gas nor true liquid. It is not a 

gas because of its high density, and it is not a liquid because no surface boundary 

exists between gas and liquid. Gas condensate reservoirs are usually deeper and 

have higher pressures, which pose special problems in the production, processing 

and recycling of the gas for maintenance of reservoir pressure. 

The quality and quantity of components in natural gas varies widely by the field, reservoir or 

location from which the natural gas is produced. Although there really is no “typical” make-up of 

natural gas, it is primarily composed of methane (the lightest hydrocarbon component) and 

ethane. Table 9.1 provides a list of substances often present in natural gas:

Table 9.1

Components Found in Natural Gas

Hydrocarbons Inerts

Substance Formula Substance Formula

Methane CH4 Helium He

Ethane C2H6 Nitrogen N2

Propane C3H8 Argon Ar

Iso-butane C4H10 Sulphur Compounds

Normal-butane C4H10 Substance Formula

Iso-pentane C5H12 Hydrogen Sulfide H2S

Normal-pentane C5H12 Mercaptan

Hexane C6H14 Sulphur S

Heptane C7H16 Other Gases

Octane C8H18 Substance Formula

Nonane C9H20 Oxygen O2

Decane C10H22 Carbon Dioxide CO2

Source: EnerPro, Inc. (1990)
134

In general, there are four types of natural gas – wet, dry, sweet, and sour. Wet gas contains 

some of the heavier hydrocarbon molecules and water vapor. When the gas reaches the 

earth’s surface, a certain amount of liquid is formed. The water has no value, however, the 

remaining portion of the wet gas may contain five or more gallons of recoverable hydrocarbons 

per thousand cubic feet. If the gas does not contain enough of the heavier hydrocarbon 

molecules to form a liquid at the surface, it is a dry gas. Sweet gas has very low concentrations 

of sulfur compounds, while sour gas contains excessive amounts of sulfur and an offensive 

odor. Sour gas can be harmful to breathe or even fatal (Berger and Anderson 1992). 

Hydrocarbons have a distinctive weight, “boiling point”, vapor pressure and other physical 

properties that make the removal and separation of individual hydrocarbons possible.42 Each 

hydrocarbon has a specific combination of pressure and temperature at which it will change 

from liquid to gas – the heavier the component, the higher the temperature, or boiling point.

9.2 Description and Typical Facilities

All natural gas is processed in some manner to remove unwanted water vapor, solids and/or 

other contaminants that would interfere with pipeline transportation or marketing of the gas. 

Typical contaminants include water, hydrogen sulfide, carbon dioxide, nitrogen, and helium. 

Centrally located to serve different fields, natural gas processing plants have two main

purposes: (1) remove essentially all impurities from the gas; and, (2) separate the gas into its 

useful components for eventual distribution to consumers. 

Figure 9.1 demonstrates the variety of natural gas compositions produced and the variety of 

natural gas processing equipment requirements. 43 Fields A and B produce natural gas and 

water. Field C produces only natural gas, no impurities. Field D produces natural gas

contaminated with some non-hydrocarbon gases. 

Fields A and B share a field-gas process facility that removes some of the water – enough to 

make it marketable.44 Field C does not require a field gas process facility because it produces 

only natural gas with no impurities. Field D requires a field facility to remove the nonhydrocarbon gases to make the remaining marketable. All four fields are connected to the gas 

processing plant, where essentially all of the water and impurities are removed and sent to 

disposal sites. (See Chapter 6 for detailed discussion of Waste Management Facilities.) 

Natural gas liquids such as ethane, propane and butane are separated within the plant and sold 

as liquid fuel, as feedstock for petrochemical manufacturers, or as an additive for blending with 

refined crude oil products. 

 

42 “Boiling point” is when a liquid will boil whenever the vapor pressure of a liquid is equal to the 

pressure being exerted on it.

43 This example is replicated from: Anthony J. Welker, The Oil and Gas Book . (Tulsa: SciData 

Publishing), 1985, p. 192.

44 The facilities located at or near the natural gas field are usually limited to making the natural gas 

stream marketable. Therefore, field gas processing facilities typically remove gas impurities only to the 

extent actually required by the transportation company taking the gas to the processing plant.
135

As natural gas is cooled, heavier substances, like pentane and butane, will change from gases 

to liquids before the lighter components, like methane, which requires a very low temperature to 

condense. At cool enough temperatures and/or high enough pressures, methane will

theoretically be the only hydrocarbon left in a gaseous form while the remaining substances will 

have been transformed to liquids (Figure 9.2). 

Figure 9.1. Variety of Natural Gas Processing Procedures.

Source: Welker (1985) 

Figure 9.2. Natural Gas Processing Products.

Natural Gas 

Processing Plant

A

B

C

D

Impurities to 

sales or disposal

Natural gas

for fuel

Natural gas

liquid products

Legend

Gas field

Field gas process facility

Gas processing plant

Water vapor

removal Nonhydrocarbon gas removal

Natural Gas 

Processing Plant

A

B

C

D

Impurities to 

sales or disposal

Natural gas

for fuel

Natural gas

liquid products

Legend

Gas field

Field gas process facility

Gas processing plant

Water vapor

removal Nonhydrocarbon gas removal

Natural Gas 

Processing Plant

A

B

C

D

Impurities to 

sales or disposal

Natural gas

for fuel

Natural gas

liquid products

Legend

Gas field

Field gas process facility

Gas processing plant

Water vapor

removal Nonhydrocarbon gas removal

Natural Gas 

Processing Plant

A

B

C

D

Impurities to 

sales or disposal

Natural gas

for fuel

Natural gas

liquid products

Legend

Gas field

Field gas process facility

Gas processing plant

Water vapor

removal Nonhydrocarbon gas removal

Natural Gas 

Stream

Residue Gas 

Gas Liquids

Ethane

Propane

Butane

Natural 

Gasoline

Industrial

Commercial

Residential

Fuels

Chemical 

Feedstock

Fuels

PROCESSING END USE

Methane

Natural Gas 

Stream

Residue Gas 

Gas Liquids

Ethane

Propane

Butane

Natural 

Gasoline

Industrial

Commercial

Residential

Fuels

Chemical 

Feedstock

Fuels

PROCESSING END USE

Methane
136

In general, these “phase changes” are what enable most gas processors to separate the

heavier hydrocarbons from the methane. The efficiency of the extraction will depend on the 

type of process utilized. The following procedures are common to natural gas processing

systems (EnerPro, Inc. 1990).

• Lease Separation: The mechanical removal of condensate and free water from the 

natural gas stream at the lease separator.

• Impurities Removal: The removal of problem, corrosive and/or toxic substances, 

such as water, carbon dioxide and hydrogen sulfide, as well as the removal of 

substances which reduce the overall heating value of the gas, such as nitrogen.

• Natural Gas Liquid Extraction: Various processes capable of liquefying and

extracting heavier hydrocarbons from methane.

• Residue Gas Conditioning: Any necessary dehydration and recompression of the 

residue gas in preparation for pipeline transmission.

• Separation of Natural Gas Liquids: The fractionation process that isolates natural 

gas liquids into distinct components. Many gas plants do not possess fractionation 

facilities and sell only the combined liquid stream.

Types of Processing Plants: Gas processing plants use several methods to extract the liquid 

components from the natural gas. At the temperatures and pressures existing in the gathering 

systems, the hydrocarbon components or natural gas liquids (NGLs or liquids) remain mixed 

with natural gas in vapor form. In order to extract these NGLs, the gas must either be

compressed, refrigerated, passed over liquid/solid agents which absorb/adsorb the liquids or 

some combination thereof. The following are common types of gas processing plants

(EneroPro 1990).

• Adsorption Plants: The incoming gas is passed through a solid agent, often

activated charcoal or molecular sieve, to extract the NGLs. The agent adsorbs the 

NGLs and they are later recovered through heating. These types of plants are 

inefficient and virtually obsolete.

• Refrigeration Plants: Straight refrigeration plants utilize a simple cooling process 

that condenses the liquids for recovery. These plants are fairly common and

relatively inexpensive to operate, but often have capacity restrictions.

• Lean Oil Absorption Plants: The raw gas is passed through oil utilizing a

recirculation process which allows the NGLs to be absorbed. Quantities of methane 

are also recovered with the NGLs and must be rejected before the other liquids are 

separated from the oil. These liquids are then recovered through the application of 

heat. This is an outmoded process, though some plants are still in operation. 

Additionally, these plants are complex and expensive to operate.

• Refrigerated Lean Oil Plants: These plants use the same general method as the 

Lean Oil Absorption, but refrigerate the oil to improve the efficiency of the recovery. 
137

Like the regular lean oil plants they are very complex and expensive, though several 

are still in use.

• Cryogenic Plants: Cryogenic plants use very low temperatures in the proper

combination with pressure to achieve the desired product recovery. These plants 

employ special insulated equipment with good thermal expansion properties and

require thorough dehydration and scrubbing of the gas to avoid hydrate formation 

and exchanger fouling. The expansion turbine cools the gas to very low

temperatures and improves the efficiency of the recovery. Turbo Expander and 

Joule-Thomson are the most commonly found types of cryogenic plants. These 

plants are efficient and relatively inexpensive and easy to operate.

The modern gas processing industry uses a variety of sophisticated methods to treat natural 

gas and extract natural gas liquids from the gas stream. The two most important extraction 

methods are the absorption and cryogenic processes. Together, these account for an

estimated 90 percent of total natural gas liquids production (Natural Gas Information and 

Educational Resources 1998c). 

9.3 Industry Characteristics

There are approximately 585 gas processing plants operating in the United States (as of

January 2001) – the majority of which are located in seven states: Texas, Louisiana,

Oklahoma, Colorado, Wyoming, California and New Mexico (Table 9.2). These seven states 

account for about 83 percent of the total number of plants. However, they only account for 70 

percent of processing capacity and 70 percent of throughput. As shown in Table 9.2, some 

states have processing facilities that have higher capacities than those in others. For instance, 

Alaska only has three natural gas processing facilities, but those facilities have a higher total 

capacity than all of the facilities listed in Table 9.2 from Kansas to Kentucky combined. The 

same holds true for throughput. 

Total U.S. gas plant average capacity is almost 72,000 MMcfd and current throughput

represents about 70 percent of capacity.

The total number of natural gas processing plants operating throughout the U.S. has been 

declining over the past several years as companies merge, exchange assets, and close older, 

less efficient plants (Figure 9.3). However, this trend was reversed in 1999 with a “rush of new 

capacity that has been ongoing in Louisiana” (True 2000). This recent growth is discussed

further in Section 9.5 – Industry Trends and Outlook.

With more than 4.3 bcf of natural gas processed in 2000, Louisiana continues to lead the U.S., 

followed closely by Texas with almost 4.1 bcf natural gas processed. Between them, the two 

states represent almost one half of natural gas processed within the U.S. in 2000 – as shown in 

Figure 9.4. Louisiana and Texas also extracted 56 percent of NGLs in 2000, with the majority of

liquids being produced in Texas – nearly 41 percent (Figure 9.5).
138

Table 9.2

Natural Gas Processing Plants in the United States 

(as of January 1, 2001)

Number Gas Gas

of Plants Capacity Throughput

(MMcfd)

Texas 205 17,111 12,358

Louisiana 76 19,110 12,828

Oklahoma 73 4,197 2,676

Colorado 40 1,238 1,020

Wyoming 35 4,005 2,591

California 31 1,859 1,417

New Mexico 25 2,926 2,443

Michigan 15 700 226

Kansas 13 3,102 2,231

Alabama 11 1,966 924

Utah 11 499 275

Mississippi 10 1,877 764

West Virginia 6 360 304

Montana 5 14 8

North Dakota 5 97 56

Pennsylvania 5 27 18

Arkansas 4 876 519

Kentucky 4 165 114

Alaska 3 9,525 9,298

Ohio 3 25 10

Tennessee 2 8 2

Florida 1 90 25

Illinois 1 2,100

Nebraska 1 10 8

Total U.S. 585 71,886 50,115

Source: Stell (2001) 
139

550

570

590

610

630

650

670

690

710

730

1992 1993 1994 1995 1996 1997 1998 1999 2000

Number of Plants (as of Jan. 1)

Figure 9.3. U.S. Natural Gas Processing Plants.

Source: True (2000) 

Figure 9.4. Natural Gas Processed by Top Ten States (2000).

Note: Percentages used as labels in this figure represent the percent of total natural gas processing within all 22 

reported states – not just within these 10 states shown in the figure.

Source: Energy Information Administration (2001b) 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

(billion cubic feet)

Louisiana

Texas

Alaska

Wyoming

Oklahoma

New Mexico

Kansas

Colorado

Alabama

California

25.4%

24.1%

18.4%

5.8% 5.7% 5.2%

3.6% 2.9% 2.2% 1.5%

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

(billion cubic feet)

Louisiana

Texas

Alaska

Wyoming

Oklahoma

New Mexico

Kansas

Colorado

Alabama

California

25.4%

24.1%

18.4%

5.8% 5.7% 5.2%

3.6% 2.9% 2.2% 1.5%
140

9.4 Regulations

Natural gas producers and marketers are not directly regulated. This is not to say that there are 

no rules governing their conduct, but instead there is no government agency charged with the 

direct oversight of their day-to-day business. Production and marketing companies must still 

operate within the confines of the law; for instance, producers are required to obtain the proper 

authorization and permitting before beginning to drill, particularly on federally-owned land. 

However, the prices they charged are a function of competitive markets and are no longer 

regulated by the government.

9.5 Industry Trends and Outlook

A number of factors are fueling the growth of the natural gas processing industry in the Gulf 

region. Major successes in deep-water exploration and production are increasing the volumes 

of liquids that come on shore for processing. Not only is supply of natural gas increasing from 

offshore, but onshore, demand for natural gas – in large part driven by power generation, is also 

rising. Adding to the increased need for natural gas, is the development of the liquids market –

where NGLs are increasing in value. 

Because of increased demand for natural gas as the preferred fuel for power generation and 

continued industrial growth, demand is forecasted to increase by 21 bcf/d day to approximately 

93 bcf/d by 2010 and to 102 bcf/d by 2015. In the next ten years, the compound annual growth 

rate of demand is expected to be 2.5 times greater than the growth rate for the previous twenty 

years. To supply this growth, producers are challenged to find new sources of natural gas and 

further exploit reserves from mature basins. 

Figure 9.5. Total Liquids Extracted by Top Ten States (2000).

Note: Percentages used as labels in this figure represent the percent of total natural gas processing within all 22 

reported states – not just within these 10 states shown in the figure.

Source: Energy Information Administration (2001b) 

0

50,000

100,000

150,000

200,000

250,000

300,000

(thousand barrelst)

Texas

Louisiana

New Mexico

Oklahoma

Alaska

Kansas

WyomingColorado

California

Utah

40.8%

15.2%

11.1%

9.8%

5.1% 4.9% 4.8%

2.6%

1.3% 1.2%

0

50,000

100,000

150,000

200,000

250,000

300,000

(thousand barrelst)

Texas

Louisiana

New Mexico

Oklahoma

Alaska

Kansas

WyomingColorado

California

Utah

40.8%

15.2%

11.1%

9.8%

5.1% 4.9% 4.8%

2.6%

1.3% 1.2%
141

Production from deepwater developments in the Gulf of Mexico is expected to be a significant 

new source of natural gas. This production is forecasted to increase from 2.9 bcf/d in 2000 to 

approximately 5.7 bcf/d by 2010 and to 8.2 bcf/d 2105. New supplies from the deepwater are 

expected to supply 20 percent of natural gas demand growth in the United States by 2010 and 

25 percent of U.S. demand growth by 2015. 

The deepwater Gulf is even more strategic to the U.S. in terms of crude oil and condensate 

production. In 2000, the Gulf of Mexico accounted for approximately 24 percent of total U.S. 

crude oil and condensate production. It is forecasted that by 2005, the Gulf will supply 37 

percent of total U.S. production, primarily from new production from deepwater developments. 

By 2010, the Gulf is expected to account for 43% of total U.S. crude and condensate production

(Enterprise Products Partners L.P. 2002).

Historically, U.S. Gulf Coast natural gas production has contained marginal amounts of

recoverable NGL. Newer deepwater production, however, has shown higher levels estimated in 

the 2-4 gallon per Mcf range. As a result, several cryogenic processing facilities are under

construction along the U.S. Gulf Coast, the first of which is operational in Southeast Louisiana

(Currence et al. 1999). The Discovery Project includes a 600,000 Mcf/d interstate pipeline, a 

condensate handling facility, a 600,000 Mcf/d cryogenic gas processing plant, a 42,000 bbl/d 

fractionator and 400,000 Mcf/d of deepwater gathering laterals. The assets extend from the 

deepwater Gulf offshore Louisiana to onshore delivery points about 30 miles south of New 

Orleans (Gas Daily 2002b). The Discovery project marks the first major grassroots offshore 

gathering and processing system along the Louisiana Gulf Coast in more than a decade

(Bodenhamer and Laguens 1998). 

Also, responding to the recent successes of deepwater exploration and production in the Gulf of 

Mexico, the Destin pipeline and Pascagoula gas processing plant have come online. The 

Destin pipeline originates at a junction platform at Main Pass 260 and, after coming ashore near 

Pascagoula, Mississippi, connects with 5 interstate gas transmission pipelines. The line has a 

121-mile offshore segment and a 134-mile onshore segment. The gas processing plant is 

located where the pipeline comes ashore, just before the first compressor station. 

The Pascagoula plant straddles the Destin pipeline adjacent to slug-catching facilities that are 

designed to remove retrograde condensate that may form in the pipeline.45 The slug catcher 

holds 5,000 bbl of liquids from the pipeline. Gas handling capacity is 1 bcf/d. Liquid from the 

slug catcher feeds into the condensate stabilizer. Gas from the slug catcher is dehydrated, then 

processed in two identical trains, each with a capacity of 500 MMscf/d. Each train provides 

inlet-gas cooling, dehydration, expansion, demethanization, NGL recovery and residue-gas 

compression. Condensate is delivered to truck loading, NGL is delivered by pipeline, and 

residue gas is compressed and returned to the pipeline network. Train A started up in March 

1999 and Train B started in late 1999 (True 2001).

Other recent projects are presented in Table 9.3 and include: 

 

45 Straddle plants are situated on mainline natural gas pipelines and allow operators to extract natural 

gas liquids from a natural gas stream when the market value of natural gas liquids separated from the 

natural gas stream is higher than the market value of the same unprocessed natural gas.
142

• In February 2000, along the Louisiana Gulf Coast, the Neptune gas-processing plant 

came online. The 300 MMcfd cryogenic plant near Centerville, Louisiana is a joint 

venture between Shell’s Tejas Natural Gas Liquids LLC and Marathon Oil Co. For 

the past 30 years, Exxon’s Garden City plant was the only gas processing plant for 

gas coming ashore through the Nautilus pipeline. Now a significant portion will be 

processed through Neptune. Presently, the plant is processing 200 MMcfd of 

natural gas stemming primarily from the Gulf. Approximately 16,000 bbl/d of NGLs 

are being yielded and transported via the Nautilus pipeline to the Promix fractionator 

for separation into NGL products. At maximum capacity, the plant is capable of 

producing over 25,000 bbl/d of NGLs. Plans are already under study to expand the 

Neptune plant (Gas Processors Report 2000).

• Williams completed a 600 MMcf/d gas processing plant in Coden, Alabama to

service Mobile Bay in May 1999. Also newly completed is a 300 MMcf/d processing 

plant in Markham, Texas. Fully operational since the end of 2001, the Markham 

plant is designed to process volumes from three companies – Kerr McGee Oil & Gas 

Corp, Enterprise Oil Gulf of Mexico, Inc., and Ocean Energy Inc. The producers 

have developed deepwater leases in the Nansen and Boomvang fields, located 

approximately 150 miles south of Houston in 3,500 to 3,700 feet of water (Gas

Services Division 2001).
143

Table 9.3

U.S. Processing Facilities under Construction

Added Expected

Company / Location Project Capacity

(MMcf/d)

Status Completion

Burlington Resources

 Los Cabin gas plant, WY Gas Plant 180 Construction 2002

Cheniere Energy Inc.

 Brownsville, TX LNG Regas* 550 Planning 2007

 Freeport, TX LNG Regas* 550 Engineering 2007

 Sabine Pass, TX LNG Regas* 550 Planning 2007

CMS Energy Corp

 Lake Charles, LA LNG Regas* 1200 Planning 2005

Duke Energy Field Services 

 Artesia, NM NGL 70 Engineering 2003

Dynegy Inc. 

 Chico, TX Gas plant 150 Construction 2002

 Hackberry, LA LNG Regas* 750 Planning 2003

El Paso Corp 

 Elba Island, GA LNG Regas* 360 Planning 2005

Enterprise Products

 Neptune, LA Gas plant 300 Construction 2003

ExxonMobil Corp

 Point Thompson, AK Gas plant 920 Planning 2002

Global Energy

 Champ plant, TN Gas plant 1 MMbtu Construction 2002

Louisiana Land & Expl.

 Lysite, WY Gas plant 180 Planning 2002

Mitchell Gas Services, L.P.

 Bridgeport, TX Gas plant 693,000 Construction 2002

Pioneer Natural Resources

 Irving, TX Gas plant 75 Planning 2002

Williams Cos. Inc.

 Cove Point, MD LNG Storage 3 bcf Construction 2002

 Markham, TX Gas plant 300 Construction 2002

Note: Regas* is Regasification plant.

Source: Stell (2002) 
145

10.0 NATURAL GAS STORAGE FACILITIES

10.1 Introduction

Demand for natural gas is primarily shaped by its use in heating homes and businesses. This 

demand results in an average winter demand that more than exceeds summer demand. 

Demand is more variable on a daily basis – because weather controls the duration, location and 

volume of peak demand, gas demand is essentially unpredictable. However, the gas supply 

industry must be able to deliver gas when and where it’s needed. The key element allowing this 

to happen is the underground gas storage system. 

Gas storage serves two central roles: to meet seasonal demands for gas (base-load storage) 

and to meet short-term peaks in demand (peaking storage). Peaks in demand can range from a 

few hours to a few days. To ensure that adequate natural gas supplies are available to meet 

seasonal base-load customer requirements, storage is filled during low utilization periods (April 

through October). During high utilization periods (November through March), pipeline capacity 

is supplemented with storage supplies to meet demand. Typically, gas withdrawn from storage 

can supply up to 30 percent of daily gas requirements during winter months. 

By balancing production and transmission flows throughout the year, underground storage 

enables greater system efficiency and decreases the amount of new transmission pipelines 

needed to connect producing regions to consuming regions. Pipeline companies can avoid the 

need to expand transmission facilities by using or establishing new storage facilities in markets 

where there is a strong fluctuation in demand. Customers also gain from this efficiency with 

reduced costs reflected in lower rates. 

In recent years, increased demand for natural gas in the electricity generation sector during the 

traditional off-peak period has increased competition for gas that was traditionally used to refill 

storage. This has also put an upward pressure on prices. Another trend that has changed the 

market is the use of storage to take advantage of expected price movements and to support 

futures market trading. Gas marketing entities, ranging from major corporations to individual 

brokers, are aggressively entering the market as developers, clients, and agents. 

Measures of Storage: The two most important characteristics of an underground storage 

facility are its capability to hold natural gas for future use and the rate at which gas inventory 

can be withdrawn or its deliverability rate. 

Capacity: The total capacity of a storage facility is simply the maximum volume of gas that can 

be stored as determined by the physical characteristics of the site (Figure 10.1). Total capacity 

is the total of two measurements, base gas (or cushion gas) and working gas. Base gas is the 

volume of gas required to maintain adequate pressure within the storage vessel. Base gas is 

rarely, if ever, produced – it is a permanent inventory, kept to ensure the deliverability of the 

working gas. The amount of base gas required is dependent upon the reservoir quality, number 

of wells, gas withdrawal schedule and field operating parameters. Because base gas is seldom 

produced, the ratio of base gas to working gas has a significant impact on the economics of new 

storage fields. 
146

Base gas can also include a measurement of “physically unrecoverable gas.” This is gas that is 

trapped by physical forces in the pores of the rock – it cannot be removed. In the case when a 

depleted gas reservoir is converted to storage, this is the gas that is already in the formation as 

irreducible gas saturation. 

Gas that is injected and produced during the storage cycle is working gas. This is the volume of 

gas above the designated level of the base gas – that which is available to the marketplace. 

Working gas capacity is essentially defined as total capacity minus base gas. 

Deliverability: Deliverability is a measure of the amount of gas that can be withdrawn from a 

storage facility on a daily basis. Deliverability, also known as the deliverability rate, withdrawal 

rate, or withdrawal capacity, is measured in terms of million cubic feet or dekatherms per day. 

Like any pressurized container, as gas is pumped into a storage reservoir, the pressure in the 

container rises. As gas flows out of the container, the rate of flow decreases, as does the 

deliverability. 

“The deliverability of a given storage facility is variable, and depends on factors such as the 

amount of gas in the reservoir at any particular time, the pressure within the reservoir,

compression capability available to the reservoir, the configuration and capabilities of surface 

facilities associated with the reservoir, and other factors. In general, a facility's deliverability rate 

varies directly with the amount of base and working gas in the reservoir: it is at its highest when 

the reservoir is most full and declines as working gas is withdrawn” (Energy Information

Administration 2001c).

10.2 Description and Typical Facilities

There are three principal types of reservoirs common to the underground storage of natural gas: 

Figure 10.1. Pressure and Volume Relationship for a Storage Reservoir.

Source: Gas Technology Institute (1997) 

Physically Unrecoverable Gas

Working

Gas

Base

Recoverable if surface Gas

pressure is reduced below

normal operating limits

Volume necessary 

to maintain deliverability

Maximum

CapacityGas Volume in Storage

Physically Unrecoverable Gas

Working

Gas

Base

Recoverable if surface Gas

pressure is reduced below

normal operating limits

Volume necessary 

to maintain deliverability

Maximum

CapacityGas Volume in Storage
147

• Depleted reservoirs in oil and/or gas fields;

• Aquifers – water-bearing rock formations conditioned to hold natural gas; and,

• Caverns hollowed out in salt “bed” or “dome” formations (several reconditioned 

mines are also used as gas storage facilities). 

Each reservoir has its own physical characteristics. Some are more porous than others, some 

are more permeable, and others have higher deliverability rates and cycling capacity. For 

instance, as shown in Table 10.1, salt caverns have much more flexibility than reservoirs and 

aquifers because of the lower requirements of base gas and shorter injection and withdrawal 

periods. Reservoirs and aquifers typically require a cushion of 50 percent or more of the total 

volume of gas in a facility, while the salt cavern needs only about 33 percent. In addition, the 

withdrawal period for salt caverns is only about 10 to 20 days, whereas it is 2 to 3 months for 

reservoirs and aquifers. Although salt caverns have the highest deliverability per storage site, 

they account for the least number of actual facilities and storage capacity in the U.S. The 

majority of stored gas is found in depleted oil and gas reservoirs. More detailed descriptions 

about each type of facilities are provided below.

Depleted Reservoir: The most common type of underground storage is depleted reservoirs. 

These shallow, high-deliverability fields take advantage of existing wells, gathering systems, 

and pipeline connections. Reservoirs are most commonly used because of their wide

availability and existence near existing pipeline infrastructure and major consumption areas. 

The geology of these fields is also well known since they have already been used as producing 

fields. 

However, because these reservoirs are old, they require a considerable amount of maintenance 

and monitoring to ensure gas is not being lost through a leak or into other permeable reservoirs. 

Also, as mentioned previously, reservoirs typically require 50 percent base gas. 

Aquifer Storage: Aquifers offer a storage alternative when depleted reservoirs and salt

caverns are not available. An aquifer storage field is defined as a “sub-surface facility for 

storing natural gas consisting of water-bearing sands topped by an impermeable cap rock”

(Energy Information Administration 2001c). Natural gas is injected at the top of the formation 

(which is saturated with water), and displaces the water down throughout the structure. 

Table 10.1

Characteristics of Natural Gas Storage Facilities

Storage Type

Number 

of 

Facilities

Cushion 

to 

Working 

Gas Ratio

Injection 

Period

Withdrawal 

Period

Injection/ 

Withdrawal 

Flexibility

Depleted Reservoir 336 2:1 7-8 months 2-3 months Low

Aquifer 49 2:1 7-8 months 2-3 months Low

Salt Cavern 28 1:2 20-40 days 10-20 days High

Source: Energy Information Administration (2001b) and Lagrasta et al. (1999) 
148

Aquifers exist mainly in the upper Midwest due to that region’s lack of depleted oil and gas 

reservoirs. Typically, aquifers are close to end user markets, have high deliverability from the 

combination of high quality reservoirs and the water drive during the withdrawal cycle. This 

increases the ability to cycle the working gas volumes more than once per season. 

Aquifers do, however, have drawbacks. Primarily, because of the water drive mechanism, the 

base gas requirement can be as high as 80 percent of the total gas volume. And a large 

percentage of base gas is not recoverable after the site has been abandoned. In addition, the 

lack of wells or production infrastructure – like those found at depleted reservoirs – and the 

need to test and characterize the geology and suitability of the rock formations for storage, can 

result in long development times and high development costs. Although existing water can help 

to increase the deliverability of the gas, it adds to operating costs as water production is often 

experienced during the withdrawal cycle. 

Salt Cavern Storage: Salt cavern storage sites are mined or leached underground cavities. 

This includes either salt caverns (in either bedded salt formations or salt domes) or rock caverns 

(e.g., coal mines). Caverns are ideal in that when filled with natural gas, they act as high 

pressure storage vessels with low base gas requirements (33 percent and can approach 0 

percent in emergencies) and operational flexibility. Because of the low base gas requirements 

and high deliverability from pressure, these facilities can cycle working gas four to five times per 

year. They also provide excellent seals – the salt cavern walls are essentially impermeable 

barriers – and the risk of gas leaks is small. 

The primary disadvantage of the salt cavern is the high cost of development. The leaching 

process – a process in which water is flushed through the cavern to dissolve the salt and flush it 

out – involves the circulations and disposal of enormous amounts of fresh water. “Cavern 

construction is more costly than depleted field conversions when measured on the basis of 

dollars per thousand cubic feet of working gas capacity, but the ability to perform several 

withdrawal and injection cycles each year reduces the per-unit cost of each thousand cubic feet 

of gas injected and withdrawn” (Energy Information Administration 2001c).

10.3 Industry Characteristics

As of December 2000, there was about 3.9 tcf of underground natural gas storage working gas 

capacity in the U.S., with an associated maximum deliverability of nearly 78 bcf/d. There are 

currently about 415 storage facilities operating in the U.S. Based on capacity, 86 percent of 

these facilities are depleted reservoirs, 10 percent are aquifers and 4 percent are salt caverns. 

As shown in Figure 10.2, working gas capacity is compared to deliverability; the salt caverns’ 

percent of total expands from 4 percent to 15 percent, whereas depleted reservoirs fall from 86 

percent to 74 percent. Aquifers stay about the same at 10 and 11 percent. 
149

Geographic Locations: As shown in Table 10.2 and Figure 10.3, many reservoirs are located 

near major Northeast and Midwest centers for winter heat demand. As shown in the figure 

above, depleted reservoirs account for 86 percent of working gas capacity in the U.S. One half 

of this capacity and 55 percent of depleted reservoir deliverability is found in the Northeast. In 

the Midwest, depleted reservoirs are supplemented by storage in groundwater aquifers, which 

account for 9 percent of total U.S. working gas capacity and 10 percent of total U.S.

deliverability. 

Figure 10.2. U.S. Natural Gas Storage Distribution.

Source: Gas Technology Institute (1997) 

Table 10.2

Summary of Underground Storage, by Region and Type (2000)

Depleted Gas/Oil Aquifer Storage Salt Cavern Total

Region no.

Working 

Gas 

Capacity

Daily 

Deliverability no.

Working 

Gas 

Capacity

Daily 

Deliverability no.

Working 

Gas 

Capacity

Daily 

Deliverability no.

Working

Gas 

Capacity

Daily 

Deliverability

(Bcf) (MMcf/d) (Bcf) (MMcf/d) (Bcf) (MMcf/d) (Bcf) (MMcf/d)

East 243 1,690 31,888 33 351 7,457 4 4 298 28

0

2,045 39,643

West 31 590 8,620 6 39 1,175 - - - 37 628 9,795

Gulf 74 1,089 17,166 1 1 12 23 135 11,118 98 1,226 28,296

Total 348 3,369 57,674 40 391 8,644 27 139 11,416 41

5

3,899 77,734

Note: Regions are established by the American Gas Association. AGA defines the Producing (Gulf) 

Region as TX, LA, MS, AR, OK, KS, NM; the Eastern Consuming Region as all States east of the 

Mississippi River less MS, plus IA, NE and MO; the Western Consuming Region as all States west 

of the Mississippi River less the Producing Region and IA, NE and MO.

Source: Energy Information Administration (2001c)

Working Gas Capacity Maximum Deliverability

86%

10%

4%

74%

11%

15%

Depleted Reservoir

Aquifer

Salt Cavern

Working Gas Capacity Maximum Deliverability

86%

10%

4%

74%

11%

15%

Working Gas Capacity Maximum Deliverability

86%

10%

4%

74%

11%

15%

Depleted Reservoir

Aquifer

Salt Cavern
150

The Gulf Coast has a mix of depleted reservoir and salt cavern storage. In fact, almost all of 

salt cavern storage facilities operating in the U.S. have been developed in Gulf Coast states. 

Out of all the facilities in the U.S., Gulf Coast salt caverns account for only 3.5 percent of 

working gas capacity and 14 percent of deliverability. But, because there are only 4 other salt 

caverns located in areas outside of the Gulf States, the working gas capacity of salt caverns and 

deliverability in the Gulf region is over 97 percent of all salt caverns.

Users of Underground Storage: Although the functions of market players in the storage 

industry have changed over the past decade, in general, the same end-users have benefited 

from service from the same facilities (pipelines and storage) and received their gas from the 

same group of producers. Once, it was the interstate pipelines that owned the majority of 

storage capacity. Storage was an essential organizational function for interstate pipelines. 

However, as explained in Chapter 7, the passing of Order 636 created open access and

eliminated merchant gas sales making the pipelines’ storage areas essentially function as 

warehouse operations. Pipelines may still operate the storage facilities, but the Local 

Distribution Company (LDC) owns the gas stored in them, basically paying rent. Pipelines are 

allowed to retain gas in storage only as required for operational integrity. Today, a number of 

major pipelines systems are able to operate without the benefit of storage service for the 

shippers or the pipeline’s operational control. 

Interstate Pipelines own 66 percent of the total working-gas storage capacity, but most of this 

capacity is under contract to others. About 8 percent of the storage capacity owned and

Figure 10.3. Locations of Existing Natural Gas Underground Storage Fields in the U.S.

Note: This figure is for illustrative purposes only. Exact locations and number of fields in this figure cannot 

be guaranteed.

Source: Energy Information Administration (2001b) 

Depleted Reservoir

Aquifer

Salt Cavern
151

operated by pipeline companies is actually used by the pipelines for operational balancing. The 

remainder is contracted to others, primarily the LDCs that were granted access to storage and 

transportation when the pipelines were required to abandon their merchant services under

Order 636 (Cates 2001). 

LDCs own and operate about 31 percent of the total working-gas capacity in the U.S. LDCs are 

also the primary contract holders of pipeline storage capacity, giving them ownership or

contractual rights to about 73 percent of the total storage capacity (Cates 2001). LDCs are 

responsible for serving their customers during peak demand periods regardless of price. They 

use storage for seasonal baseload and peaking service – to serve their customers directly. This 

type of capacity owner is primarily located in the northeast and usually inject into storage

starting in May and ending in October. In some cases, LDCs are required to make injections 

into storage to meet their anticipated winter demands, regardless of price. 

The regulatory changes that led to the commoditization of natural gas created the environment 

in which gas marketing companies were born. Gas Marketers move gas in and out of storage 

as changes in price levels present arbitrage opportunities.46 The use of storage to support 

arbitrage and hedging of natural gas contracts can be extremely profitable, but also carries a 

great degree of risk. Although this opportunity is available to LDCs, most do not participate due 

to restrictions placed by the state regulatory commissions. Not subject to these restrictions, 

marketers have taken positions in storage facilities around the nation to enhance their

opportunities. For marketers, seasonal factors no longer govern the use of underground 

storage inventory – supply, demand, and prices play a larger role. This role is so large that 

marketers have increased their effective control of storage assets from nearly nothing just a few 

years ago to nearly 25 percent of all capacity available today. 

Recently, however, in the wake of the Enron scandal and the exposure of other marketers’ 

unscrupulous tactics, the midstream sector of the natural gas industry has been transformed. 

Existing players are fighting for financial survival. “The ranks of the middlemen marketers who 

did much of the fixed price trading of monthly baseload have been decimated, and those

remaining are laboring under creditworthy burdens and a constant stream of new accusations 

and ratings hits. It will take time for the new entrants in the market to expand their trading 

books” (Foster Natural Gas Report 2003).

Intrastate pipelines use storage for operation balancing and system supply as well as to serve 

end-use customers. “The value of storage for intrastate pipelines, whether procured as an 

equity investment or as a service lease, is essentially identical to that for a [marketer]. Thus, the 

value is defined by the contribution that the storage service brings to their gas sales function. 

This includes the value available to suppliers in swing supply gas sales, emergency back-up 

gas sales, balancing, and no-notice service sales as well as incidental income from arbitrage 

opportunities and peaking sales” (Gas Technology Institute 1997).

The newest members to the group of storage owners are independent storage developers. 

These are typically small firms that are able to secure institutional or private financing. They are 

not associated with LDCs, pipeline companies, or oil and gas firms – hence the name

“independent.” As with marketers, developers have the ability to take advantage of price

 

46 Arbitrage refers to the trading of the same commodity on multiple markets in order to capture the 

value of any pricing variations that occur between those markets.
152

variations, employ arbitrage strategies, and develop an asset from which to sell value-added 

gas supply services. 

10.4 Regulations

Almost all storage facilities are subject to either state or federal regulation. A storage facility 

may or may not be subject to Federal Energy Regulatory Commission (FERC) regulation

depending on the market it serves. Just like pipelines, if the facility serves the interstate market,

it is subject to FERC regulations. Otherwise, the facility is state regulated. Today, almost all of 

the underground storage facilities that are subject to FERC jurisdiction operate on an openaccess basis. This means that the major portion of working gas capacity at each site must be 

made available for lease to third-parties on a nondiscriminatory basis. Before Order 636, how 

capacity was used was the decision of the pipeline owner. 

The open-access regulations originally enacted in 1985 with FERC’s Order 436 began the

transformation of the natural gas commodity market from a tightly regulated "cost of service" 

pricing structure to the free and open market in place today. FERC issued Order 636 in 1992, 

completing the transition to a deregulated natural gas commodity market. This marked the end 

of most of the traditional pipeline merchant services. Pipelines' access to storage was one

aspect to which FERC paid particular attention. FERC felt storage provided pipelines an unfair 

competitive advantage by making the transportation component of firm pipeline sales service far 

superior to the service pipelines offered to unaffiliated shippers (Cates 2001). 

Since this transformation, many storage projects have received approval to charge marketbased rates. This allows pipelines to collect for project financing, which was not allowed with 

cost-based rates. Market-based rates are particularly important in the development of new 

storage projects because they give the project sponsors the flexibility to craft rates and terms of 

service tailored to their customers' needs.

Unbundling at the state level may be a much more important issue for the growth of the storage 

industry than federal regulatory change has been. It is likely that LDCs will become more peak 

sensitive, requiring more balancing across shippers, resulting in continued disaggregation of 

utility loads, and shifting gas supply responsibilities back to suppliers. Meanwhile, the

uncertainty of outcomes will likely preclude significant investment by LDCs in storage assets 

and may result in the growth of large supplier/aggregators.

10.5 Industry Trends and Outlook

Figure 10.4 highlights the difference between the utility storage holders of the East Coast region 

and energy marketers of the Gulf Coast region. The gas storage patterns show that the East 

Coast region working gas volumes have peaked at 1,918 bcf over the last 7 years with a 

variance of only 17 bcf. Utilities meet their commitments to deliver gas in the winter by filling 

their storage during the summer. Gulf Coast storage levels are more variable, averaging 770 

bcf at the beginning of the withdrawal season over the last 7 years with a variance of 250 bcf –

gas marketers fill and withdraw storage based on their ability to capture price arbitrage. 
153

Figure 10.4. Working Gas in Storage by Region.

Source: Dietert and Pursell (2000) and Energy Information Administration (2002a) 

West Coast working gas is significantly smaller than the other regions and has a limited impact 

on the overall natural gas storage market. Storage levels are relatively consistent seasonally 

and they are somewhat isolated from the East Coast and Gulf Coast regions by the Rocky

Mountains.47

The refill season of 2000 experienced somewhat high natural gas prices, driving storage 

injections down by about 10 percent compared to 1999. Many storage users limited their rate of 

injections, in anticipation that prices would drop later in the season. This led to low storage 

levels and in turn, increased the pressure on natural gas prices entering the winter of 2000-

2001. Generally, LDCs can recover the costs of higher gas prices through their cost-of-service 

rates; however, restructuring has placed storage operators and marketers at greater risk of not 

recovering costs. 

Then the 2000-2001 heating season began with two very cold months. November and

December were colder than normal; 43 and 32 percent colder than the previous year,

respectively. When gas demand suddenly increased in the winter of 2000-2001, gas storage 

levels were well below average, and gas prices reached peak levels. By the end of December, 

natural gas storage levels were almost 27 percent below the 5-year average for that point in the 

heating season. Nationally, working gas inventories ended the heating season about 5 percent 

below the all-time end-of-season low of 758 bcf in March 1996 (Energy Information

Administration 2001d). Fortunately, milder temperatures in late January through mid-February 

 

47 This discussion and following figure is a replication of a discussion in the following publication, with 

updated data from the EIA Natural Gas Monthly, 1995 through 2001: Jeff A. Dietert and David A. Pursell, 

Underground Natural Gas Storage, (Houston: Energy Industry Research, Simmons & Company

International), June 2000.

0

500

1,000

1,500

2,000

2,500

Jan-95

Jul-95

Jan-96

Jul-96

Jan-97

Jul-97

Jan-98

Jul-98

Jan-99

Jul-99

Jan-00

Jul-00

Jan-01

Jul-01

Jan-02

Jul-02

Working Gas in Storage (Bcf)

Gulf Coast East West

Peak Working Gas

0

500

1,000

1,500

2,000

2,500

Jan-95

Jul-95

Jan-96

Jul-96

Jan-97

Jul-97

Jan-98

Jul-98

Jan-99

Jul-99

Jan-00

Jul-00

Jan-01

Jul-01

Jan-02

Jul-02

Working Gas in Storage (Bcf)

Gulf Coast East West

Peak Working Gas
154

relieved the pressure on withdrawals. Had withdrawals continued at the same rate as earlier in 

the winter, U.S. gas in storage could have dipped below the 500 bcf level, at which withdrawals 

would have been very problematic. As it turned out, the U.S. storage level at the end of the 

season stood above that critical level at 724 bcf (Gas Daily 2001a).

The goal of 2001 was to replenish storage to normal levels. By the middle of June – only twoand-a-half months into the refill season – storage levels were half full. For the week ending 

June 15, 2001, 106 bcf was placed into underground facilities, putting storage levels 115 bcf 

ahead of where they were in 2000 and 42 bcf ahead of the previous 5-year average (Gas Daily 

2001b). Injections continued at a record pace, and by July, storage inventories were 59 percent 

full. Despite four consecutive weeks of colder temperatures in February and March of 2002, an 

overall milder winter in 2002 kept working gas at almost 39 percent or nearly 500 Bcf above the 

5-year average of 1,251 bcf (Energy Information Administration 2002b).

Inventory: Based on a 2001 survey conducted as part of development of this Fact Book and 

GIS database, 20 natural gas storage facilities are located in the Gulf region; 9 in Texas, 7 in 

Louisiana, 3 in Mississippi, and 1 in Alabama. Of the 20 fields, 15 are salt domes and the 

remaining five are depleted reservoirs. Capacity ranges from 2,700 to 120,000 MMcf. 

New Additions: A number of new storage facilities were announced in 2002 – a number of 

which are salt caverns located in Gulf States. Some of these additions/expansions include:

• Market Hub Partners (a unit of Duke Energy Gas Transmission) is proceeding with 

plans to convert an underground salt dome in Copiah County, Mississippi into a 3 bcf 

storage facility. Market Hub Partners estimates the facility to be online as early as 

spring 2004. The facility is in close proximity to a number of interstate pipelines and 

already plans on expanding by as much as 6 bcf of additional storage capacity (Gas 

Daily 2001c). 

• A new storage facility in Lamar County, Alabama will have a capacity of 2 bcf with 

deliverability of 20 MMcf/d. Northwest Alabama Gas District is in the process of

completing the conversion of the depleted gas reservoir and says that it may be able 

to expand the facility to 8 bcf with 120 MMcf/d of deliverability. Since the utility will 

only use about 1 bcf to serve the needs of its customers, it is looking for interested 

parties and is also working with power companies that are considering building a 

power plant at the site of the storage facility (Gas Daily 2001d).

• Bay Gas Storage is in the process of leaching the McIntosh salt dome formation in 

McIntosh, Alabama. The cavern, when complete will have a total working gas 

capacity of 3.5 bcf. The leaching process is scheduled for completion by December 

2002. This is the company’s second gas storage cavern in McIntosh. When it is 

completed, Bay Gas will have a total working gas capacity of 6 bcf and a withdrawal 

capacity of 225 MMcf/d (Gas Daily 2001e).

• Unocal Global is constructing a high deliverability salt cavern near Kermit, Texas 

called the Keystone Gas Storage Project. The facility should begin operations in the 

summer of 2002. It is projected that the Keystone project will initially have 3 bcf of 

capacity, with 100 MMcf/d injection and 200 MMcf/d withdrawal capacity (Unocal 

2001).
155

• Virginia Gas and Duke Energy are working on expanding capacity at a Saltville, 

Virginia facility. The companies plan to expand the salt cavern facility from 1.1 bcf to 

10 bcf and build an interconnect with East Tennessee Natural Gas System (also 

owned by Duke). At full capacity the Saltville site will be able to deliver up to 500 

MMcf/d to area markets (Gas Daily 2001f).

• Seneca Lake Storage plans to develop a high deliverability natural gas storage 

facility in depleted salt caverns in Reading, New York. The facility should be 

operational by November 2002 and will have a working gas capacity of 300,000 

decatherms (dth) and a deliverability of 50,000 dth/d. 

Evolution of R&D Needs: “As peak day natural gas demand continues to grow, the need for 

more flexible gas storage will also increase. With increasing peak requirements for all regions, 

caused primarily by growth in residential space heating, peaking storage (5 to 20 days) rather 

than seasonal storage (over 70 days) will be needed. The need for increased deliverability is 

also influenced by the fact that overall storage deliverability will naturally decline due to factors 

related to the age and condition of the wells and infrastructure” (Gas Technology Institute 1997). 

This does not include the amount of natural gas that will be needed to fuel new electric power 

plants projected to be built in the next 20 years. 

New methods of storing gas are being researched. Particularly in areas that do not have the 

right geology for conventional gas storage in underground formations (i.e., South Atlantic,

Pacific Northwest). And in some areas, where suitable geology exists, existing conventional 

storage does not meet the requirements of end users. The Department of Energy’s Strategic 

Center for Natural Gas has awarded over $2.5 million in contracts to major universities and 

corporations to research and develop ways to help expand the gas storage system. Current 

technology development efforts include (Office of Fossil Energy 2002):

• Novel and advanced fracture simulation technologies and improved remediation 

treatments that will increase storage reservoir deliverability and help to offset the 

reported 5.2 percent annual decline in deliverability.

• The development of improved gas flow metering and energy measurement

technologies that will provide real-time, automated monitoring of pipeline gas flow 

and energy content, increasing system deliverability, and optimizing gas sales to 

customers; and

• Advanced storage technologies that will meet the specific storage needs of new and 

growing industrial and power generation markets, specifically the short-term or hourly 

requirements of the power generation sector. 

The development of advanced technologies would result in a more efficient natural gas storage 

system, benefiting both industry and consumers. The industry would gain from increased

deliverability, decreased revitalization costs, and increased operating efficiency. Improved 

system reliability and flexibility would benefit LDCs, industrial, and power generation end-users, 

while residential customers would gain from lower costs of service. 
157

11.0 REFINERIES

11.1 Introduction

Petroleum is a mixture of liquid hydrocarbons usually located beneath the earth's surface. The 

exact composition of these hydrocarbons – which are found in both gaseous and liquid form –

varies according to locality. Hydrocarbons found in the gaseous state are called “natural gas”, 

whereas that in the liquid form is “petroleum”. Crude oil is a mixture of hydrocarbon compounds 

and relatively small quantities of other materials such as oxygen, nitrogen, sulfur, salt, and 

water. It varies by site in color and composition, from a pale yellow, low viscosity liquid to a 

heavy black 'treacle' consistency. Because it is of little use in its raw state, further processing of 

crude oil is necessary to unlock the full potential of this resource. 

A refinery is an organized arrangement of manufacturing units designed to produce physical 

and chemical changes to turn crude oil into petroleum products. In the refinery, most of the 

non-hydrocarbon substances are removed from crude oil and it is broken down into its various 

components, and blended into useful products. 

Petroleum provides many such products, the most notable being motor gasoline and heating 

fuel. Its many uses include fuel for automobiles, trucks, agricultural and industrial machinery, 

trains, ships, and aircraft. Petroleum is used to heat homes, offices, and factories and to grow, 

process, package, distribute, refrigerate, and cook food. Petroleum is also a source of synthetic 

fabric for cloths as well as detergents and dry cleaning solvent. Moreover, it provides a

chemical base for cosmetics and pharmaceutical products as well as for many plastic products 

from toys to building materials (Energy Information Administration 1999c). The following are 

just a few products that get their start in a refinery:

• Ammonia • Guitar strings • Pingpong paddles

• Antiseptics • Heart valves • Plastic beverage containers

• Bubble gum • Ice chests • Roller-skate wheels

• Crayons • Insect repellant • Sneakers

• Denture adhesive • Life preservers • Synthetic fibers

• Eyeglass frames • Liquid detergent • Telephones

• Fertilizer • Mascara • Tobacco pouches

• Floor polish • Paint • Volleyballs

Figure 11.1 provides a depiction of additional petroleum products and 1999 percent refinery 

yields for each product category. 
158

Asphalt and

Road Oil

Paving

Roofing

Waterproofing

(3.1%)

Petroleum Coke

Carbon

Electrodes

Fuel Coke

Electric Switches

(4.4%)

Lubricants

Lubricating Oils

Greases

Transmission Oils

Household Oils

Textile Spindle

Oils

(1.1%)

Residual Fuel

Oil

Boiler Fuel

Refinery Fuel

BunkerFuel

Wood

Preservative

(4.3%)

Petrochemical

Feedstocks

Alcohols, Resins,

Ethers

Fibers

Medicines

Cosmetics

(2.5%)

Distillate Fuel

Oil

Home Heating

Oil

Diesel Fuel

Refinery Fuel

Industrial Fuel

(21.1%)

Kerosene

Illumination

Space Heating

Cooking

Tractor Fuel

(0.4%)

Special Naphthas

Solvents

Paint Thinner

(0.6%)

Kerosene - Type

Jet Fuel

(9.6%)

Still Gas Refinery

Fuel

(4.1%)

Motor Gasoline

(43.9%)

Aviation Gasoline

(0.2%)

Liquefied Refinery

Gases

Petrochemical

Feedstocks

Space heating

Cooking

Synthetic Rubber

(4.2%)

Waxes

Used for:

Fruits, Vegetables,

Candy, Chewing gum,

Candles, Matches,

Crayons, Pencils,

Sealing Wax, Canning

Wax

(0.1%)

Miscellaneous Products

Absorber Oil

White Machinery Oils

Cutting Oils

Candymaking/Baking Oils

Technical Oils

Medicinal

Salves/Ointments

Petroleum Jelly

Acetic Acid

Sulfuric Acid

Fertilizers

(0.3%)

Figure 11.1. Petroleum Products and Uses (1999 Percent Refinery Yield).

Source: Energy Information Administration (1999c) 
159

11.2 Description and Typical Facilities

Refineries vary in size, sophistication and cost depending on their location, the types of crude 

they refine and products they manufacture. Because crude oil is not a homogeneous raw 

material – varying in color, viscosity, sulfur content and mineral content – that which is produced 

from different fields or geographic areas have different quality characteristics that give rise to 

different values. 

Every refinery begins with the separation of crude oil into different fractions by distillation. The 

fractions are further treated to convert them into mixtures of more useful saleable products by 

various methods such as cracking, reforming, alkylation, polymerization and isomerization. 

These mixtures of new compounds are then separated using methods such as fractionation and 

solvent extraction.

Because there are various blends of different crude oils available, different configurations of 

refining units are used to produce a given set of products. A change in the availability of a 

certain type of crude oil can affect a refinery’s ability to produce a particular product. For 

instance, one important crude quality is gravity. Gravity is a measure of the density of the crude 

oil – the lower the gravity of the crude, the “heavier” the crude. Heavy oil is viscous, does not 

flow well and has a high carbon to hydrogen ratio along with a high amount of carbon residues, 

asphaltenes, sulphur, nitrogen, heavy metals, aromatics and/or waxes. Conversely, if crude oil 

has a higher gravity, the crude oil is lighter. 

A second quality measure is sulfur content. Sulfur content is usually measured in terms of the 

percentage of the crude’s weight that is comprised by sulfur. Low sulfur or “sweet” crudes 

typically have less then 0.5 percent sulfur. Crude oil considered high sulfur or “sour” typically 

has over 0.5 percent sulfur content. These quality characteristics are often identified in crude oil 

naming conventions, e.g., Heavy Louisiana Sweet, West Texas Intermediate, and Wyoming 

Sour. Each of these names corresponds to a crude stream from a particular producing area or 

field with a well-recognized set of quality characteristics.

These two qualities (gravity and sulfur content) are important in refining. Heavy crudes require 

more sophisticated processes to produce lighter, more valuable products; therefore, they are 

expensive to manufacture. Because of its corrosive qualities, higher sulfur content makes crude 

more expensive to handle and process. In general, light crudes are more valuable, i.e., they 

yield more of the lighter, higher-priced products than heavy crudes. The product slate at a given 

refinery is determined by a combination of demand, inputs and process units available, and the 

fact that some products are the result (co-products) of producing other products.

Development of the Refining Process: Refinery processes have developed in response to 

changing market demands for certain products. A summary of the refining process is presented 

in Figure 11.2. 
160

Figure 11.2. The Refining Process.

Source: Australian Institute of Petroleum (2000) 

The practice of refining began with the simple distillation of many different raw materials in 

Europe in the 18th century to see if new products could be obtained. Coal, shale, tar, and whale 

oil were all experimented with. As the demand for coal oil and kerosene, although odorous and 
161

smoky, began to grow with an increasing need for illumination, the discovery of a process for 

making a clean burning fuel met a ready market.48

The new industry of petroleum refining focused on crude oil distillation for kerosene until two 

significant events changed the market: (1) the invention of electric light decreased the demand 

for kerosene and (2) the invention of the internal combustion engine created a demand for 

diesel fuel and gasoline. In the early 1900’s, the growing number of automobiles rapidly 

increased the demand for motor fuel and stimulated the development of new refinery processes 

to increase gasoline yields and improve the quality of the finished product.

The first downstream process that changed the petroleum refining industry was thermal

cracking, which subjects heavy fuels to both pressure and intense heat, physically breaking the 

large molecules into smaller ones to produce additional gasoline and distillate fuels. 

Other refining developments followed in the late 1920’s and early 1930’s: 

• Polymerization produces high octane gasoline from by-products of thermal cracking 

(olefins). 

• Vacuum distillation further processes the product remaining in the bottom of the 

crude oil distillation column that will not distill at atmospheric pressure. 

• Vis-breaking, another thermal cracking process can make product left from the

vacuum distillation flow more easily. This process reduces the product’s viscosity 

(the thick, gluey quality that impedes product flow). 

• Coking, another severe thermal process, produces fuel gas, gasoline blending

stocks, distillates, and petroleum coke from products left from atmospheric or

vacuum distillation. 

• Alkylation, a process in which a catalyst is used to produce a high quality gasoline 

component was developed during World War II when the petroleum industry focused 

its technological expertise on products essential to the war effort, especially high 

quality aviation fuel. This process became widely used after the war to produce

gasoline blending stocks. 

Other technological advances included catalytic cracking and isomerization. Similar to thermal 

cracking, catalytic cracking utilizes a catalyst to accelerate the rate of the reaction. 

Isomerization uses heat and a catalyst to convert straight-chained hydrocarbon molecules to 

branched-chained hydrocarbon molecules with the same chemical composition. This produces 

high quality gasoline blending stocks called isomers and increases the octane number of the 

light gasoline components, normal pentane and normal hexane, that are found in light, straight 

run gasoline.

A major development in the late 1940s was catalytic reforming, a process for converting low 

grade naphthas to high octane gasoline. In the mid-1950s a process called hydrotreating was 

 

48 Unless otherwise noted, the information in this sub-section is based on: Energy Information

Administration, Petroleum: An Energy Profile, (Washington D.C.: Department of Energy), July 1999c, pg. 

27-28.
162

developed to remove contaminants that would damage the catalyst used in catalytic reforming. 

Hydrocracking, a process using hydrogen and catalysts to convert middle boiling range or 

residual products into lighter products was developed in the 1960’s. 

11.3 Industry Characteristics

As of January 1, 2001, the 150 petroleum refineries in the U.S. ranged in size from small 

refineries able to process 5,000 barrels of crude oil per day to those able to process more than 

400,000 barrels per day. Their combined crude oil refining capacity totaled over 16 million 

barrels per calendar day. 

As with most aspects of the U.S. oil industry, the Gulf Coast is by far the leader in refinery 

capacity (Figure 11.3). Over 45 percent of the total U.S. refining capacity resides in the Gulf 

Coast region, which holds over one-third of the petroleum refineries in the U.S. As shown in 

Figure 11.3, most of the region’s refineries are located in Texas and Louisiana. Texas has 26 

refineries, with a combined crude oil distillation capacity of over 4 million barrels per day. 

Louisiana has 17 refineries with over 2.6 million barrels per day of distillation capacity. 49 

 

49 This discussion is replicated from Energy Information Administration, Petroleum: An Energy Profile, 

(Washington D.C.: Department of Energy), July 1999, pg. 29-30; with figures updated from Energy 

Information Administration, Petroleum Supply Annual 2000, Volume 1, (Washington D.C.: Department of 

Energy), June 2001, p. 80.

Figure 11.3. U.S. Refineries and Capacity by State as of January 1, 2001.

Note: PAD District stands for Petroleum Administration for Defense Districts. These districts were delineated 

during World War II to facilitate oil allocation.

Source: Energy Information Administration (2001e) 

Number of Operable Refineries

Operable Crude Oil Distillation Capacity

PAD District I

PAD District III

PAD District II

PAD District IV

PAD District V

1

5

17

2,672

4

335

3

130

2

61

3

96

26

4,265

5

469

1

170

23

1,919

6

358

2

148

2

5

5

600

4

167

5

140

2

85

4

152

1

58

6

1,018

2

433

3

294 2

228

1

74

2

335

4

526

1

33

5

760

4

547

1

162 1

60

1

16

Number of Operable Refineries

Operable Crude Oil Distillation Capacity

PAD District I

PAD District III

PAD District II

PAD District IV

PAD District V

1

5

17

2,672

4

335

3

130

2

61

3

96

26

4,265

5

469

1

170

23

1,919

6

358

2

148

2

5

5

600

4

167

5

140

2

85

4

152

1

58

6

1,018

2

433

3

294 2

228

1

74

2

335

4

526

1

33

5

760

4

547

1

162 1

60

1

16
163

Table 11.1 shows the “top ten” refining states in the U.S. These states – with the highest 

individual crude oil distillation capacity – account for 65 percent of the number of operable 

refineries and 81 percent of the U.S. total distillation capacity. 

The Gulf Coast is also the nation’s leading supplier in refined products as in crude oil. It ships 

refined product to both the East Coast (supplying more than half of that region’s need for light 

products like gasoline, heating oil, diesel, and jet fuel) and to the Midwest (supplying more than 

20 percent of the region’s light product consumption).50

As shown in Figure 11.4, the East Coast imports over half of all of the products that come to the 

U.S., because it is the largest consuming area in the U.S. And, for historical reasons, it has only 

enough capacity to meet around one-third of those needs from its own refining capabilities. As 

shown in Figure 11.5, the East Coast fills the product gas with supplies from other parts of the 

U.S., particularly the Gulf Coast and with imports. Its limited volume of refining capacity also 

keeps it a distant third as a crude importer. However, because its local production is so small, 

its crude import dependency is the highest of all regions, at almost 100 percent. 

 

50 This, and the rest of this Section’s discussion is taken from: Energy Information Administration, Oil 

Market Basics, (Washington D.C.: Department of Energy), http://www.eia.doe.gov/pub/oil_gas/ 

petroleum/analysis_publications/oil_market_basics/default.htm, (4 June 2002). 

Table 11.1

Top Ten Petroleum Refining States as of January 1, 2002

Number of Operable Crude Oil

Operable Distillation

State Refineries Capacity

(bbl/d)

Texas 26 4,265,430

Louisiana 17 2,672,200

California 23 1,919,150

Illinois 6 1,017,885

Pennsylvania 5 760,000

Washington 5 599,880

New Jersey 4 547,000

Ohio 4 525,500

Oklahoma 5 469,095

Idaho 2 433,000

Subtotal 97 13,209,140

U.S. Total 150 16,320,171

Source: Energy Information Administration (2001e) 
164

Figure 11.4. Imports of Crude Oil and Petroleum Products by PAD District (2000).

Note: PAD District stands for Petroleum Administration for Defense Districts. These districts 

were delineated during World War II to facilitate oil allocation.

Source: Energy Information Administration (2002b) and Energy Information Administration

(2001e)

Figure 11.5. Movements of Petroleum Products between U.S. Regions (2000).

Note: PAD District stands for Petroleum Administration for Defense Districts. These districts were 

delineated during World War II to facilitate oil allocation.

Source: Energy Information Administration (2002b) and Energy Information Administration (2001e) 

0

1,000

2,000

3,000

4,000

5,000

6,000

East Coast

(PAD I)

Midwest 

(PAD II)

Gulf Coast

(PAD III)

Rockies 

(PAD IV)

West Coast

(PAD V)

(thousand barrels per day)

Crude Oil

Products and Other

Feedstocks

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

To East Coast

(PAD I)

To Midwest 

(PAD II)

To Gulf Coast

(PAD III)

To Rockies 

(PAD IV)

To West Coast

(PAD V)

(thousand barrels per day)

From PAD V

From PAD IV

From PAD III

From PAD II

From PAD I 
165

The only other region that imports significant amounts of products is the Gulf Coast. Its focus is 

not, like the East Coast's, on products that can be supplied directly to the consumer, but on 

refinery feedstocks and blendstocks, to support its role as the main U.S. refining and

petrochemical center. That role, plus the need for all the Midwest’s non-Canadian crude 

imports to move through the Gulf Coast’s ports and pipelines too, has also led to the Gulf Coast 

being by far the most important crude oil importing region in the United States, accounting for 

nearly two-thirds of the total. 

As seen in Figure 11.5, the trade among regions of the U.S. is focused on the eastern half of the 

country. The Midwest and East Coast account for 90 percent of the inter-regional flow, the flow 

between PAD Districts. The Gulf Coast is by far the largest supplier, accounting for more than 

80 percent of the inter-PADD flow. In contrast, the Rockies and the West Coast are isolated, in 

petroleum logistics terms, from the rest of the country. The easy flow of petroleum from the Gulf 

Coast to the Midwest and the East Coast mean that incremental supply is more readily available 

to those markets in the event of a demand surge or supply drop. In contrast, the West Coast, 

and the California market in particular, cannot so readily attract incremental supplies. Thus, the 

California refinery outages that occurred in the spring of 1999 resulted in a large price increase 

as market players scrambled for additional supply, none of which was available close at hand, 

or cheaply. The California market's isolation is more than just geographic: the state imposes 

unique and stringent quality restrictions on both its gasoline and its off-highway diesel, making 

what otherwise might be available to augment California product supplies unsuitable.

11.4 Regulations

Although actual refineries are not regulated economically per se, they are affected by

environmental and political legislation. Also affecting the refining industry are regulations placed 

on the way petroleum is produced, imported, stored, transported and consumed in the U.S. The 

following is a description of three major changes in the petroleum industry that have directly 

impacted the refineries as well.51

Petroleum Price and Allocation Decontrol: In early 1981, the U.S. Government responded to 

the oil crisis of 1978-1980 by removing price and allocation controls on the oil industry. For the 

first time since the early 1970s, market forces replaced regulatory programs and domestic crude 

oil prices were allowed to rise to a market-clearing level. Decontrol also set the stage for the 

relaxation of export restrictions on petroleum products.

Soon after deregulation, many small refineries and older, inefficient plants could no longer

compete and were forced to shut down. The loss of so many small, low-conversion refineries, 

which were a large source of unfinished oils, sent many sophisticated refiners overseas for 

intermediate oil supplies. From 1980, the last full year of price and allocation controls, to 1981, 

imports of unfinished oils more than doubled, jumping from 55,000 barrels per day to 112,000 

barrels per day. Unfinished oils imports continued to rise and in 1993, peaked at 491,000 

barrels per day. In 2000, the U.S. imported an average of 274,000 barrels per day of unfinished 

oils. 

 

51 The following descriptions are taken from: Energy Information Administration, Petroleum 

Chronology of Events 1970-2000, (Washington D.C.: Department of Energy), May 2002, 

<http://www.eia.doe.gov/pub/oil_gas/petroleum/analysis_publications/chronology/petroleumchronology20

00.htm> (3 June 2002).
166

Decontrol of crude oil prices allowed producers to raise prices to the market-clearing level for 

the first time since the early 1970s, and domestic crude oil prices became more closely aligned 

with foreign crude oil prices. The production sector responded by increasing crude oil

exploration and production in the lower 48 states during the first half of the 1980s. However, 

sharply falling oil prices in 1986 reversed this upward trend in domestic exploration and 

production. Increases in Alaskan North Slope (ANS) production during this period aided the 

domestic crude oil situation. This helped to stem the flow of imported crude oil, greatly reducing 

U.S. reliance on OPEC crude oil. Imports remained low until crude oil prices collapsed in 1986. 

Reid Vapor Pressure Regulations of 1989 and 1992: To combat emissions of volatile organic 

compounds (VOC's) and other ozone precursors, the Environmental Protection Agency

implemented a two-phased program limiting summertime motor gasoline volatility (the rate at 

which gasoline evaporates into the air) in some U.S. urban areas in the spring of 1989. VOC's 

react photochemically in the atmosphere and are a major component of smog. Lowering the 

vapor pressure of motor gasoline reduces concentrations. At warm temperatures and high 

altitudes, gasoline evaporates more readily, increasing the amount of VOC's released to the 

atmosphere. Alaska and Hawaii are exempt from the volatility restrictions. 

• Phase I summer volatility standards went into effect in 1989. This phase mandated 

that the average summer Reid Vapor Pressure (RVP) in motor gasoline be reduced 

from 11.5 pounds per square inch (psi) to a maximum of 10.5 psi RVP, and as low as 

9.0 psi RVP in certain areas of the country. 

• Phase II summer volatility standards were implemented in 1992 and stayed in effect 

through the summer of 1994. In 1995, RVP requirements changed again with the 

implementation of the reformulated gasoline program. Phase II set a nationwide 

maximum summer RVP standard of 9.0 psi. Gasoline sold in southern cities that do 

not meet Federal ozone standards must meet an even stricter standard of 7.8 psi 

RVP. 

Refiners met the Phase I standards by reducing the amount of normal butane blended into 

motor gasoline. Butane is a lower-cost gasoline blending component that has a relatively high 

RVP and high octane. To compensate for the loss in volume and octane in motor gasoline 

when butane was removed, refiners increased crude oil inputs and the use of catalytic cracking 

and alkylation units. The more stringent Phase II standards increased requirements for

downstream processing (further processing of crude oil and unfinished oils that occurs after they 

are initially run through the crude oil distillation unit). Some refiners made large capital

investments to produce high-octane, lower RVP blending components, to meet these standards. 

Clean Air Act Amendments of 1990: Amendments to the Clean Air Act of 1970 imposed strict 

new controls to reduce mobile sources of air pollution. The Amendments contained six

provisions to be implemented by the EPA in stages between November 1, 1992, and January 1, 

2000. Four major programs to reduce harmful emissions from highway fuel were to go into 

effect between November 1, 1992, and January 1, 1996. These programs included: 

• Oxygenated Fuels Program: As of November 1, 1992, all motor gasoline sold in 

most of the 39 areas of the country designated as carbon monoxide (CO) nonattainment areas must contain a minimum of 2.7 percent oxygen by weight during at 
167

least four winter months. Adding oxygenates to gasoline lowers the level of carbon 

monoxide produced when a car engine is turned on. Concern over poisonous 

nitrogen oxide emissions from the higher winter oxygen content resulted in a winter 

maximum of 2.0 percent oxygen by weight in California's CO non-attainment areas. 

• Highway Diesel Fuel Program: As of October 1, 1993, the sulfur content of

highway diesel fuel was reduced from a maximum of 0.25 percent to 0.05 percent by 

weight. In addition, the cetane index, which measures the self-ignition quality of 

diesel fuel, must be maintained at a minimum of 40. Small refineries received relief 

from the sulfur limit in the form of tradeable credits until December 31, 1999.

• Reformulated Gasoline Program: As of January 1, 1995, reformulated gasoline 

was required in the nine metropolitan areas with the worst ozone problems. Other 

areas may "opt in" to the program by applying to the EPA. The "opt-in" provision 

may be delayed for up to three years if EPA determines that not enough

reformulated gasoline is available. Reformulated gasoline must meet specific 

composition and emission performance criteria. The core emission requirements for 

1995 to 1999 prohibit any increase in nitrous oxides emissions and mandate a yearround reduction of toxic air pollutants and a summertime reduction of volatile organic 

compounds of 15 percent below 1990 "baseline" gasoline. By 2000, TAP and VOC 

emissions are to be reduced by a minimum of 20 percent. If technically feasible, a 

25-percent cut will be mandated. 

• Leaded Gasoline Removal: Sales of leaded motor gasoline were prohibited after 

1995. 

In preparation of this program, refineries began constructing oxygenates production facilities –

at least 33 refineries had facilities for producing oxygenates in 1992. By the beginning of 1993, 

production capacity for oxygenates had increased 59 percent from 1991. Construction of

desulfurization units, in particular catalytic hydrocracking and hydrotreating units, accelerated 

after 1980 as heavier, higher-sulfur crude oils became available to U.S. refiners. More projects 

were started to increase desulfurization capacity to remove sulfur from products and to comply 

with the 1990 Amendment’s on-highway diesel fuel regulations. Small refineries lacking 

desulfurization equipment could choose to produce only distillate fuel oil for non-highway use or 

modify their current refinery processes.

11.5 Industry Trends and Outlook 

The U.S. refining industry’s ability to meet short-term increases in demand can also be

measured by the rate at which operable capacity is utilized. The utilization rate is expressed as 

a percent and represents gross inputs to crude oil distillation units divided by operable capacity. 

This rate fluctuates as refinery operations adjust to changes in demand. It reflects changes in 

refinery operations more rapidly than capacity changes do. For example, capacity expansions 

began in response to high demand levels through the early and mid-1970s, and continued to 

come online even after demand peaked in 1978. At the same time, gross inputs to distillation 

units leveled off and turned downward in response to declining demand. As a result, refinery 

utilization declined steadily from 1978 to 1981, evidencing a slowdown in refinery activity that 

was not reflected in capacity figures until 1982 (Energy Information Administration 1999).
168

However, during the 1980s, the U.S. refining industry experienced a net loss of 120 refineries 

and approximately 3 million barrels per day of operable capacity. Conversely, there was a 

steady rise in U.S. demand for petroleum products after 1983. Consequently, the amount of 

gross inputs to refineries rose steadily every year since then. In response to rising demand for 

refined petroleum products, the average annual refinery utilization rate increased from 69

percent in 1981 to almost 93 percent in 2000. 

The refining industry in the 1990s was also characterized by low product margins and

profitability. Although demand for refined products was strong and inventories were low,

capacity had “simply outpaced demand growth and industry participants have played a game of 

chicken in which competitors are waiting for each other to shut down their units... [b]ut nobody 

wants to be the first” (National Petroleum News 1996). In addition to the extra capacity, another 

factor that had an impact on the industry was regulatory requirements. New requirements for 

reformulated gasoline contributed to the overcapacity by sparking a round of upgrades that 

added to production ability and capacity. In addition, amendments to the Clean Air Act impaired 

refiners by adding capital costs in a time of flat demand. 

As shown in Figure 11.6, the number of operable refineries in the U.S. has been steadily 

declining since the large decrease of the 1980s. However, the operable capacity has remained 

stable – indicating that although there has been a significant loss in the number of refineries, 

operating capacity in those that remain is increasing. “Falling demand for petroleum and the 

deregulation of the domestic refining industry in the 1980s led to 13 years of decline in U.S. 

refinery capacity. That trend was reversed in 1995, and 1.2 million barrels per day of distillation 

capacity had been added by 2000. Financial, [environmental,] and legal considerations make it 

unlikely that new refineries will be built in the United States, but additions at existing refineries 

are expected to increase total U.S. refining capacity [in the long-run]” (Energy Information 

Administration 2000b). Today, the refinery business is at the other end of the spectrum from the 

previous two decades. As stated above, the annual refinery utilization rate in 2000 was almost 

93 percent. Refineries are now operating at peak capacity almost year-round, there’s no spare 

capacity to bring on in an emergency (Fletcher 2001).
169

According to the EIA’s Annual Energy Outlook 2001, distillation capacity is projected to grow 

from the 2000 year-end level of 16.3 million barrels per day to 18.2 million in 2020 in the low 

economic growth case and 18.8 million in the high growth case, compared with the 1981 peak 

of 18.6 million barrels per day. Almost all the capacity additions are projected to occur on the 

Gulf Coast. Existing refineries are expected to continue to be utilized intensively throughout the 

forecast, in a range from 91 percent to 95 percent of design capacity. In comparison, the 2000 

utilization rate was 93 percent, well above the rates of the 1980s and early 1990s. Additional 

“downstream” processing units are expected to allow domestic refineries to produce less

residual fuel, which has a shrinking market, and higher value “light product” such as gasoline, 

distillate, jet fuel, and liquefied petroleum gases.

Inventory: Table 11.2 provides results of a 2001 inventory of refineries located in the Gulf 

region servicing the offshore oil industry conducted as part of development of this Fact Book 

and GIS database. Of the 36 facilities inventoried, 23 were located in Texas, 2 were located in 

Alabama, and 1 was located in Mississippi. 

Figure 11.6. Number and Capacity of Operable Petroleum Refineries.

Source: Energy Information Administration (2001e) 

0

50

100

150

200

250

300

350

1970 1975 1980 1985 1990 1995 2000

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

Number of Refineries Crude Oil Distillation
170

Table 11.2

Refineries in the Gulf Region

Name City State

COASTAL MOBILE REFINERY CHICKASAW AL

SHELL CHEMICAL SARALAND AL

BP AMOCO REFINERY BELLE CHASSE LA

CALCASIEU REFINERY LAKE CHARLES LA

CITGO REFINERY LAKE CHARLES LA

CONOCO REFINERY WEST LAKE LA

CONVENT REFINERY CONVENT LA

EXXON MOBIL REFINERY CHALMETTE LA

MARATHON/ASHLAND REFINERY GARYVILLE LA

MURPHY OIL REFINERY MERAUX LA

PLACID REFINING CO PORT ALLEN LA

ST. ROSE REFINERY NORCO LA

CHEVRON USA INC PASCAGOULA MS

BP AMOCO CORPORATION TEXAS CITY TX

CITGO REFINING & CHEMICALS CORPUS CHRISTI TX

COASTAL REFINING & MKTG CORPUS CHRISTI TX

CROWN CENTRAL 

 PETROLEUM CORP PASADENA TX

DEER PARK REFINERY DEER PARK TX

EXXON COAL USA INC BAYTOWN TX

FINA OIL AND CHEMICAL CO PASADENA TX

FINA OIL AND CHEMICAL CO PORT ARTHUR TX

HOWELL HYDROCARBONS 

 & CHEMICALS CHANNELVIEW TX

JAVELINA CO CORPUS CHRISTI TX

KOCH PETROLEUM CORPUS CHRISTI TX

LUBRIZOL CORP DEER PARK TX

LUBRIZOL CORP PASADENA TX

LYONDELL-CITGO REFINING HOUSTON TX

MARATHON ASHLAND PETROLEUM TEXAS CITY TX

MOBIL OIL CORP BEAUMONT TX

MOTIVA ENTERPRISES LLC PORT ARTHUR TX

PHILLIPS PETROLEUM SWEENY TX

PREMCOR REFINING GROUP INC PORT ARTHUR TX

SARTOMER CO INC HOUSTON TX

VALERO REFINING CO HOUSTON TX

VALERO REFINING CO TEXAS CITY TX

VALERO REFINING CO & MKTG CO CORPUS CHRISTI TX

Source: Acadian Consulting Group, Inc., 2001; The Louis Berger Group, Inc. 2001
171

12.0 PETROCHEMICAL PLANTS

12.1 Introduction

The chemical industry converts raw materials (oil, natural gas, air, water, metals, minerals) into 

more than 70,000 different products (Figure 12.1). After natural gas is processed and crude oil 

is refined, the non-fuel components remaining are known as petrochemicals. Petroleum is 

composed mostly of hydrogen and carbon compounds (called hydrocarbons). It also contains 

nitrogen and sulfur, and all four of these ingredients are valuable in the manufacture of

chemicals. Because these chemicals are derived from petroleum, they are named

petrochemicals. 

“The boundaries of the petrochemical industry are rather fuzzy. On the ‘upstream’ end, they 

blend into the petroleum refining sector, which furnishes a major share of petrochemical

feedstocks; ‘downstream,’ it is often impossible to draw a clear line between petrochemicals 

manufacturing and other organic chemistry-based industries such as plastics, synthetic fibers, 

agricultural chemicals, paints and resins, and pharmaceuticals” (Tussing and Kramer 1981). 

Operating in this field are petroleum companies who have broadened their interests into

chemicals, chemical companies who buy petroleum raw materials, and joint ventures between 

chemical and petroleum companies, amongst many others.

Raw Materials

Oil,

Natural Gas,

Coal

Benzene

Ethylene

Propylene

Xylene

Toulene

Butadiene

Methane

Butylene

Outputs

Agricultural Chemicals

Foam

Food Packaging

Insulation

Carpeting

Paints Dry Cleaning

Furniture Fiber Pipe & Fittings

Bottles

Resins

Auto Parts

Pharmaceuticals

Cements

Detergents

Adhesives

Lubricants

Tires

Toys

Cosmetics

Textiles

Figure 12.1. Organic Chemicals and Building Blocks Flow Diagram.

Source: Office of Compliance (1995) 
172

Petrochemicals are part of a group known as organic chemicals – those containing carbon. 

This group or sector is classified by the Bureau of Census with an SIC code of 286. The 286 

category includes gum and wood chemicals, cyclic organic crudes and intermediates, organic 

dyes and pigments, and industrial organic chemicals not elsewhere classified. This SIC 286 

includes a number of integrated firms that are also engaged in petroleum refining and

manufacturing of other types of chemicals at the same sites. 

Processes: The transformation of raw materials into chemical products requires chemical, 

physical and biological separation and synthesis processes (Table 12.1). These processes 

expend large amounts of energy for heating, cooling or electrical power (refer to Figures 12.2 

and 12.3 later in this chapter). Separations play a critical role and account for 40 to 70 percent 

of both capital and operating costs. The most widely used separation process is distillation, 

which accounts for as much as 40 percent of the industry’s energy use (Energy Information 

Administration 2000c). Chemical synthesis and process heat also play major roles in nearly all 

chemical operations. 

Table 12.1

Industry Specific Technologies

Unit Operation Purpose Major Technologies

Separations Separate products, 

remove contaminants, dry 

solids

Distillation, extraction, absorption, 

crystallization, evaporation, drying, steam 

stripping or cracking membranes

Chemical Synthesis Synthesize chemicals, 

polymers and resins

Catalytic reactions (oxidation, 

hydrogenation, alkylation) and 

polymerization, hydration, hydrolysis, 

electrolysis

Process Heating Drive chemical reactions 

and separations; can be 

direct or indirect

Direct heating: furnaces, kilns, dryers

Indirect heating: boilers, heat exchangers

Heat transfer fluids: steam, boiling water, 

organic vapors, water, oils and air

Source: Energy Information Administration (2000c)

The industrial organic chemical sector includes thousands of chemicals and hundreds of

processes. In general, a set of building blocks (feedstocks) is combined in a series of reaction 

steps to produce both intermediate and end-products. Among the processes of importance in 

petrochemical manufacture are (Waddams 1969):

• Distillation: A technique of separation which makes use of the difference in volatility 

or boiling point of different components in a mixture. The use of successive

vaporization and condensation, separates the mixture into lighter and heavier

portions.
173

• Solvent Extraction: This is the separation of a component(s) of a mixture by using 

a liquid with selective solvent characteristics. This operation is used for the

separation of components by types, for example, the separation of aromatics from 

paraffins.

• Crystallization: By chilling a solution in a filter or centrifuge, solid crystals that have 

been separated out can be recovered. 

• Absorption: A form of solvent extraction, a component of a gas or vaporized 

mixture is separated by selective absorption, usually in a liquid solvent. The

operation is commonly carried out in a packed tower. 

• Adsorption: Certain highly porous materials (e.g., activated charcoal, silica gel) 

have the power of condensing on their surfaces large amounts of vapors. Where this 

adsorption can be operated selectively, it represents a technique for the separation 

of one component from a mixture. 

• Cracking: In petroleum terminology, this means the breaking down of the large 

hydrocarbon molecules into molecules of lower molecular weight. This is achieved in 

the absence of air, by high temperature along or by combination of high temperature 

and catalytic activity. 

• Reforming: This refers to processes designed to upgrade gasoline quality in

petroleum refining. This uses heat and usually a catalyst to transform hydrocarbons 

into other hydrocarbons or mixtures of hydrocarbons and oxides of carbon, with air or 

steam taking part in the reaction.

• Alkylation: This is usually the reaction of a hydrocarbon such as an alkane or 

aromatic with an olefin using an acid or other catalyst.

• Isomerization: Designed to induce a rearrangement of atoms within a particular 

molecule, in the petroleum field it is commonly applied to the conversion of a normal 

paraffin to the isoparaffin.

• Polymerization: A polymer results from a catalyst being employed to form very 

large molecules from small molecules. 

12.2 Description and Typical Facilities

Industrial organic chemical facilities have an unusual distribution when compared to

downstream manufacturing facilities. Most significantly, a small number of very large facilities 

account for the majority of the industry’s value of shipments (Table 12.2). In 1992, 113 of the 

986 industrial organic chemical facilities had more than 250 employees. Nonetheless, these 

facilities accounted for at least 65 percent of the value of shipments for the industry. About 25 

percent of the total value of shipments came from the largest 16 plants (greater than 1,000 

employees) (Office of Compliance 1995).
174

The chemical industry uses a variety of fuel sources, nearly 50 percent of which are used as 

feedstocks. The industry is the single largest consumer of natural gas (over 10 percent of the 

domestic total) and uses virtually all the liquified petroleum gas (LPG) consumed in U.S. 

manufacturing (Figure 12.2). Other energy sources include byproducts produced onsite, hot 

water, and purchased steam (Energy Information Administration 2000c). 

Table 12.2

Organic Chemical Facility Characteristics

Percent of

Number of Number of Percent of Shipment

Employees Facilities Facilities Value

< 10 259 26% 1%

10 – 49 301 31% 5%

50 – 249 313 32% 27%

250 – 499 60 6% 16%

500 – 999 37 4% 26%

1,000 + 16 2% 25%

Total 986 100% 100%

Source: Office of Compliance (1995) 

Figure 12.2. Chemical Industry Energy Use by Fuel – 1994 (trillion Btu).

Source: Energy Information Administration (2000c) 

Natural Gas

2,569; 40%

LPG

1,535; 24%

Electrical Losses

1,047; 16%

Coal

293; 5%

Net Electricity

520; 8%

Other

287; 5%

Fuel Oil

124; 2%

Natural Gas

2,569; 40%

LPG

1,535; 24%

Electrical Losses

1,047; 16%

Coal

293; 5%

Net Electricity

520; 8%

Other

287; 5%

Fuel Oil

124; 2%
175

Sites for chemical manufacturing facilities are typically chosen for their access to raw materials 

and to transportation routes. And, because the chemical industry is its own best customer, 

facilities tend to cluster near such end-users. 

Laid out like industrial parks, most petrochemical complexes include plants that manufacture 

any combination of primary, intermediate, and end-use products. Changes in market conditions 

and technologies are reflected over time in the changing product slates of petrochemical

complexes. In general, petrochemical plants are designed to attain the cheapest manufacturing 

costs and thus are highly synergistic. Product slates and system designs are carefully

coordinated to optimize the use of chemical by-products and to use heat and power efficiently. 

Nearly 50 percent of the energy used within the industry is transformed into chemical products. 

For example, liquefied petroleum gases (a mixture of gases such as ethylene, ethane, propane, 

propylene) serve as feedstocks for the manufacture of polyethylene, polypropylene, and a host 

of other products. Also, natural gas is used to produce ammonia, a raw material used in the 

production of many fertilizers (Energy Information Administration 2000c). 

Organic chemicals (ethylene, propylene, and many others) have by far the highest energy 

requirements of all chemical sectors – about 50 percent of total industry energy use (Figure

12.3). More than 50 percent of energy consumed in organic chemicals manufacture is in the 

form of energy feedstocks (natural gas and LPG). Inorganic chemicals are made from ores, air 

and water and therefore require little or no feedstock energy.

Figure 12.3. Sector Energy Use – 1994 (trillion Btu).

Source: Energy Information Administration (2000c) 

0

500

1,000

1,500

2,000

2,500

3,000

Inorganic Chemicals Organic Chemicals Plastics/Rubber/Fibers Agri-chemicals

Energy Use, No Feedstocks Feedstock
176

Ethylene Production: Because different facilities are operated by different companies, using 

different supplies of raw materials and producing various different end-products, there is really 

no “typical” petrochemical plant or facility. However, we can discuss one type of product that is 

produced and seen as the industry’s most basic building block. Ethylene is used in myriad 

consumer products such as detergents, cosmetics, textiles, and antifreeze. It is also used for 

many different types of plastics, including polyethylene plastics, from which items such as trash 

bags and milk jugs are made. Ethylene is also used within the industry for the production of 

other derivative products. 

Ethylene is mainly produced through the steam cracking of hydrocarbon feedstocks. 

Feedstocks used for steam cracking range from ethane to naphtha and gas oils. Some 

ethylene is also produced as a byproduct of petroleum refining. Stored in large underground 

caverns ethylene is then transported to customers through a pipeline system or fully refrigerated 

ships.

Olefin plants, which produce petrochemicals, have existed for well over 50 years. These plants 

have grown considerably in size over the past few decades. The output of olefin plants that was 

formerly recorded in pounds per year, now is measured in tons per year. The so-called worldscale plant (the size that achieves whatever is currently considered full economies of scale) is 

larger than many medium-sized refineries (Burdick and Leffler 1990). 

The early olefin plants were designed to use only ethane and propane as feedstocks mostly 

because of the high output ratio of ethylene that these two fuels could produce. During the 

energy crisis of the late 1970s, it was believed that natural gas resources were going to be 

exhausted and therefore new plants that used heavier feedstocks, such as naphtha and gas 

oils, were developed. As late as the early 1990s, these plants produced approximately half of 

ethylene yields. With the introduction of the mega-plants and the increased availability of 

natural gas, the industry is currently moving back toward the use of propane and ethane as 

feedstocks.

Of the top 10 ethylene production complexes in the world, six are found in the U.S.; five are 

located in Texas and one in Louisiana. These six production complexes only account for 35 

percent of the U.S.’s ethylene production capacity (Nakamura 2002).

12.3 Industry Characteristics

Texas, New Jersey, Louisiana, North Carolina and Illinois are the United State’s top chemical 

producers. However, most of the basic chemicals production is concentrated along the Gulf 

Coast, where petroleum and natural gas feedstocks are available from refineries. About 70 

percent of all primary petrochemicals are produced in Texas and Louisiana. Ten states

accounted for 62 percent of chemicals production and 60 percent of chemical industry

employment in 1996 (Figure 12.4). 52 

 

52 Unless otherwise indicated, this section is based on: Energy Information Administration. 2000c. 

Chemical Industry Analysis Brief, (Washington D.C.: Department of Energy), January 2000,

<http://www.eia.doe.gov/emeu/mecs/iab/chemicals/ index.html>, (2 October 2000).
177

As previously mentioned, six of the top 10 largest ethylene production complexes in the world 

are found on the Gulf Coast. Louisiana gets 6.6 percent of its GDP from these petrochemical 

shipments, higher than any other state. The chemical industry in Texas accounts for 3 percent, 

which may seem small, but it’s the largest value – $57.4 billion. Production in these states also 

seems to be the most efficient. According to Figure 12.4, it takes only 30,000 employees in 

Louisiana to produce a value almost comparable to that of New Jersey’s 99,000 employees. 

Twice the number of employees in Illinois produce a value that is almost $3 billion less than that 

of Louisiana. And, Texas’ value of shipments is almost double that of New Jersey, with 14,000 

thousand fewer employees. 

A keystone to the U.S. economy, the chemical industry provides over 2 percent of the total GDP 

and almost 12 percent of the manufacturing GDP. The U.S. is the largest chemical producer in 

the world and achieved a record trade surplus in 1997 of $19.2 billion. The industry continues 

to grow, with profits in 1997 reaching $44.8 billion. Shipments have increased more than 5 

percent every year over the last decade. Industry composition has changed, however, with an 

increasing emphasis being placed on high-technology fields (e.g., pharmaceuticals, 

biotechnology, advanced materials). Pharmaceuticals is the highest valued sector (24% of 

shipments), followed by organic chemicals (21%) and plastics (16%) (Table 12.3) (Energy 

Information Administration 2000c).

$

%

Value of Shipments (billions of dollars)

Employment (000s)

% of Total Gross State Product

$

%

17.2

73.0

1.0%

$

%

57.4

85.0

3.0%

$

%

23.5

30.0

6.6%

$

%

12.1

39.0

5.5%

$

%

21.1

49.0

5.3%

$

%

19.2

66.0

3.1%

$

%

15.4

67.0

3.2%

$

%

26.4

99.0

5.5%

$

%

12.4

56.0

1.4%

California

Texas

Louisiana

S. Carolina

N. Carolina

$

%

20.7

62.0

2.4%

Illinois Ohio

New Jersey

New York

Pennsylvania

Figure 12.4. Value of Shipments for Top Ten States (1996).

Source: Energy Information Administration (2000c) 
178

12.4 Regulations

Although petrochemical plants are not regulated economically per se, they are affected by

nearly all federal environmental statutes. The industry is also subject to numerous laws and 

regulations from state and local governments designed to protect and improve the nation’s 

health, safety and environment. The following is a summary of the major federal regulations 

that affect the chemical industry (Office of Compliance 1995).

Toxic Substances Control Act (TSCA): TSCA gives the EPA comprehensive authority to 

regulate any chemical substance whose manufacture, processing, distribution in commerce, use 

or disposal may present an unreasonable risk of injury to health or the environment. Three 

sections are of primary importance to the organic chemical industry. TSCA §5 mandates that 

chemical companies submit pre-manufacture notices that provide information on health and 

environmental effects for each new product and test existing products for these effects. TSCA 

§4 authorizes the EPA to require testing of certain substances. TSCA §6 gives the EPA 

authority to prohibit, limit or ban the manufacture, process and use of chemicals. 

Clean Air Act (CAA): The original CAA authorized EPA to set limits on chemical plant

emissions. Many of these new source performance standards (NSPS) apply to organic 

chemical manufacturers including those for flares, storage vessels, synthetic organic chemical 

manufacturers equipment leaks, synthetic organic chemicals manufacturers using air oxidation 

processes, distillation operations, reactor processes, and wastewater.

The Clean Air Act Amendments of 1990 set control standards by industrial sources for 41 

pollutants to be met by 1995 and for 148 other pollutants to be reached by 2003. Several 

provisions affect the organic chemical industry. Under the air toxics provisions of the CAAA, 

more sources are covered including small businesses. In April 1994, the EPA proposed

regulations to reduce air toxics emissions at chemical plants. The Hazardous Organic National 

Emissions Standard for Hazardous Air Pollutants, also known as HON, covers hundreds of 

Table 12.3

Value of Shipments within Chemical Industry (billion dollars, 1996)

Product Value of 

Shipment

Pharmaceuticals $ 86.5

Organics $ 75.7

Plastics $ 59.6

Soaps/Cleaners $ 51.8

Inorganics $ 27.7

Misc. $ 24.5

Agri-chemicals $ 23.4

Paints $ 18.3

Source: Energy Information Administration (2000c) 
179

chemical plants and thousands of chemical process units. The HON also includes innovative 

provisions such as emissions trading that offer industry flexibility in complying with the rule's 

emissions goals. Subsets of the industry are regulated under other National Emission

Standards for Hazardous Air Pollutants (NESHAP). These include vinyl chloride manufacturers, 

benzene emission from ethylbenzene/styrene manufacturers, benzene equipment leaks,

emissions from storage tanks, benzene emissions from benzene transfer operations, and

benzene waste operations.

Clean Water Act: The Clean Water Act, first passed in 1972 and amended in 1977 and 1987, 

gives EPA the authority to regulate effluents from sewage treatment works, chemical plants, and 

other industrial sources into waters. The act sets “best available” technology standards for 

treatment of wastes for both direct and indirect (to a Publicly Owned Treatment Works)

discharges. In 1987, EPA proposed final effluent guidelines for the organic, polymer and 

synthetic fiber industry. The majority of this rule was upheld by the federal courts. A final 

proposal for the remaining portions of the rule was issued in August 1993. The implementation 

of the guidelines is left to the states who issue National Pollutant Discharge Elimination System 

(NPDES) permits for each facility.

The Storm Water Rule requires the capture and treatment of stormwater at facilities producing 

chemicals and allied products, including industrial organic chemical manufacture. Required 

treatment will remove from stormwater flows a large fraction of both conventional pollutants, 

such as suspended solids and biological oxygen demand (BOD), as well as toxic pollutants, 

such as certain metals and organic compounds.

Superfund: The Comprehensive Environmental Response Compensation and Liability Act of 

1980 (CERCLA) and the Superfund Amendments and Reauthorization Act of 1986 (SARA) 

provide the basic legal framework for the federal “Superfund” program to clean up abandoned 

hazardous waste sites. The 1986 SARA legislation extended those taxes for five years and 

adopted a new broad-based corporate environmental tax. In 1990, Congress passed a simple 

reauthorization that did not substantially change the law but extended the program authority 

until 1994 and the taxing authority until 1995. The chemical industry (all SIC codes) pays about 

$300 million a year in Superfund chemical feedstock taxes. A comprehensive reauthorization 

was considered in 1994. The industry believes several serious concerns need to be addressed 

including the liability standard which threatens Potentially Responsible Parties (PRPs) with the 

entire cost of clean-up at sites even though they may be responsible for only a tiny fraction of 

the waste; clean-up requirements, which are often unaffordable, unattainable, and unjustified by 

the risks presented by the sites; and the punitive, adversarial nature of the enforcement

program.

Title III of the 1986 SARA amendments (also known as Emergency Response and Community 

Right-to-Know Act, EPCRA) requires all manufacturing facilities, including chemical facilities, to 

report annual information to the public about stored toxic substances as well as release of these 

substances into the environment (42 U.S.C. 9601). This is known as the Toxic Release

Inventory (TRI). Between 1988 and 1993 TRI emissions by chemical companies to air, land, and 

water were reduced 44 percent. EPCRA also establishes requirements for federal, state, and 

local governments regarding emergency planning. In 1994, over 300 more chemicals were

added to the list of chemicals for which reporting is required.

To date, EPA has focused much of its attention on measuring compliance with specific

environmental statutes. This approach allows the Agency to track compliance with the Clean 
180

Air Act, the Resource Conservation and Recovery Act, the Clean Water Act, and other

environmental statutes. Within the last several years, the Agency has begun to supplement 

single-media compliance indicators with facility-specific, multimedia indicators of compliance. In 

doing so, EPA is in a better position to track compliance with all statutes at the facility level, and 

within specific industrial sectors.

12.5 Industry Trends and Outlook

According to the Oil and Gas Journal (2000), petrochemical construction projects have

dominated worldwide expansion and construction forecasts in recent years (Figure 12.5):

In 2001, ethylene markets experienced a slowdown in demand, mainly due to the economic 

turndown. As a result, many producers scaled back throughput. However, the downturn, 

combined with new capacity, led to historically low cash margins for U.S. producers. U.S. 

operating rates were also low, at 82 percent of total capacity in 2001 – the lowest levels since 

the early 1990s. 

Excess capacity for all of North America was about 5.4 million metric tons for 2001. North 

American ethylene demand was 35.4 million metric tons in 2001; therefore, demand was about 

30.0 million metric tons, a decrease of 1.0 million metric tons from 2000. Figure 12.6 shows that 

favorable economics for reinvesting in steam crackers will not occur until 2004 (Nakamura 

2002). 

Figure 12.5. Type of Construction Projects – 1996 to 2000 Average.

Source: Oil and Gas Journal, (2000) 

0

50

100

150

200

250

300

350

400

Petroleum Refining Pipelines Gas Processing

US

Middle East

Latin America

Europe & FSU

Canada

Asia Pacific

Africa
181

Even with the decrease in demand, the industry has seen only one plant retired in the past year. 

Chevron Phillip’s Sweeny plant, which could produce 181,000 tons of ethylene per year (a very 

small amount by today’s plant sizes), was decommissioned as it had last been operated in 

December 2000 (Nakamura 2002).

Producer margins have also been impacted by the run up of natural gas prices that began in the 

year 2000. LPG, which closely follows natural gas prices, and natural gas have been the fuel of 

choice in the newest mega plants. Double-digit natural gas prices have added to the burden of 

slack worldwide demand for ethylene.

As methods of transporting petrochemical products are reduced, U.S. producers must consider 

international opportunities to compete with what have been historically regional markets. The 

tradeoff for many international opportunities is between the benefit of low-cost international gas 

resources and the political risks of their international investments. Countries that lack

infrastructure to use natural gas as a fuel will either flare or reinject these gas resources. The 

economics in this situation are recognized as the price of natural gas and its byproducts

continue to rise. Plant economics, therefore, can stack up favorably in countries where gas 

resources have little commercial value. This puts pressure on the competitiveness of U.S. 

plants since they must purchase marketable gas at existing market prices.

Mergers: The number of U.S. ethylene, low linear density polyethylene and benzene

companies have decreased in recent years. These mergers have not lead to a major

concentration of companies, but they have achieved scale and other fixed cost savings. In 

February 2001, Union Carbide Corp. became a wholly owned subsidiary of Dow Chemical Co. 

Dow is now the leading supplier of ethylene in the world. Second to Dow’s 10.7 million metric 

tons per year capacity is ExxonMobil’s 7.9 million metric tons per year. Chevron Phillips 

Figure 12.6. U.S. Ethylene Economics.

Source: Nakamura (2002) 
182

Chemical Co. LP, based in Houston, now ranks seventh among worldwide ethylene producers. 

All of its plants are in Texas. 

Figure 12.7 shows the difference between the top five shareholders of North American ethylene 

capacity between 1995 and 2005. Fewer companies are taking a larger share of the total 

ethylene market (Chang 2001). This trend, as mentioned previously, results from the

economies of scale that the new mega-capacity facilities are able to achieve. For example, the 

largest plant in the U.S. is two-thirds the size of the tenth largest worldwide producer’s total 

assets. Two plants of this size would put a producer at approximately seventh on the top ten list 

worldwide.53

Inventory: An inventory of petrochemical facilities located in the Gulf region was conducted in 

2001 as part of development of this Fact Book and GIS database. Seventy-one petrochemical 

facilities were recorded within the Gulf: 53 were located in Texas, 17 in Louisiana, and 1 in 

Mississippi.

Table 12.4 presents a list of construction or expansion projects underway for petrochemical 

plants in the U.S. As the table illustrates, new facilities are still being added in the U.S. even 

though demand faded over the past year. Additionally, only two plants on the list are not 

located in Texas.

 

53 This has been confounded by the merger and acquisition activities and consideration that has 

occurred throughout the past decade.

Figure 12.7. Top Shareholders of North American Capacity.

Source: Chang (2001) 

All Others

57%

Dow

12%

Shell

8%

Exxon

8%

Nova

8%

Union 

Carbide

7%

All Others

38%

Chevron

Phillips

10% Nova

8%

Exxon

Mobil

12%

Equistar

14%

Dow

18%

Total ethylene capacity = 61.7 billion lb Total ethylene capacity = 86.2 billion lb 

1995 2005

All Others

57%

Dow

12%

Shell

8%

Exxon

8%

Nova

8%

Union 

Carbide

7%

All Others

38%

Chevron

Phillips

10% Nova

8%

Exxon

Mobil

12%

Equistar

14%

Dow

18%

Total ethylene capacity = 61.7 billion lb Total ethylene capacity = 86.2 billion lb 

All Others

57%

Dow

12%

Shell

8%

Exxon

8%

Nova

8%

Union 

Carbide

7%

All Others

38%

Chevron

Phillips

10% Nova

8%

Exxon

Mobil

12%

Equistar

14%

Dow

18%

Total ethylene capacity = 61.7 billion lb Total ethylene capacity = 86.2 billion lb 

1995 2005
183

Table 12.4

Petrochemical Construction/Expansion Projects in the United States

Added Expected

Company / Location Project Capacity Status Completion

(tons/year)

Adkins Energy LLC

Lena, IL Ethanol 68,000 Construction 2002

American Acryl

Bayport, TX Acrylic acid 120,000 Construction 2002

Atofina Petrochemicals Inc.

Carville, LA Polystyrene 230,000 Engineering 2002

BASF Corp.

Port Arthur, TX Propylene 315,000 Planning 2003

BP America, Inc.

Alvin, TX Ethylene 220,000 Engineering 2005

Chevron Phillips Chemical Co

LP / Solvay Polymers Inc.

Baytown, TX HDPE 318,000 Construction 2002

Shell Chemical LP

Deer Park, TX Ethylene 544,000 Construction 2003

Sterling Chemicals Co

Texas City, TX Acetic Acid Engineering 2003

Source: Stell (2002) 
185

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Appendix I 

Infrastructure Database Description & Queries 
199 

Infrastructure Types/Data 

Platform Fabrication Yards 

• Name 

• Owner 

• Location (lat/long, address) 

• Contact (phone #) 

• Commercial Operation Date 

• Size 

• Platform Types 

Port Facilities 

• Name 

• Owner 

• Location (lat/long, address) 

• Contact (phone #) 

• USACE Waterway Name/Code 

• USACE Waterway Name/Code 
200 

Shipyards/Shipbuilding 

• Name 

• Owner/Operator 

• Location (lat/long, address) 

• Contact (phone #) 

• Commercial Operation Date 

• Size 

• Shipyard Type Maximum Vessel length/width 

Repair, Maintenance Yards and Supply Bases 

• Name 

• Owner 

• Location (lat/long, address) 

• Contact (phone #) 

• Commercial Operation Date 

• Size 

• Total number stations, full-time employees 

• Transportation access 

Waste Management Facilities 

• Name 

• Owner 

• Location (lat/long, address) 

• Contact (phone #) 

• Commercial Operation Date 

• Size 

• Permit/Permit Agency 

• Facility Class 

• Percentage Oil Waste 

• Facility Type (e.g. salt dome, injection, land fill, landfarm, recycling) 

• Waste types handled (e.g., NOW, NORM) 

• Capacity 

• Transportation access 

Pipelines 

• Location (lat/long) 

Pipe Coating 

• Name 

• Owner 

• Location (lat/long, address) 

• Contact (phone #) 

• Commercial Operation Date 

• Size 

• Yard capacity 

• Maximum pipeline coating size (dia) 
201 

Gas Processing Plants 

• Name 

• Owner 

• Location (lat/long, address) 

• Contact (phone #) 

• Commercial Operation Date 

• Size 

• Operation capacity in MMcf per day 

• Total number pipelines connected (number offshore/number interstate) 

Natural Gas Storage Facilities 

• Location (lat/long) 

Refineries 

• Name 

• Owner 

• Location (lat/long, address) 

• Contact (phone #) 

• Commercial Operation Date 

• Size 

• Input delivery by e.g., pipeline, tanker, barge 

• Products 

• Production capacity (barrels per calendar day) 

• Number employees 

• Annual Operating Hours 

 

Petrochemical Plants 

• Name 

• Owner 

• Location (lat/long, address) 

• Contact (phone #) 

• Commercial Operation Date 

• Size 

• Primary product & capacity 

• Secondary product & capacity 

• Other products & capacities 

• Number employees 

• Number production-related employees 

• Annual operating hours 

 

Heliports 

• Name 

• Owner 

• Location (lat/long, address) 

• Contact (phone #) 

• Current status 
202 

Queries 

Attribute 

Infrastructure type 

Name of Facility 

Cities 

Counties 

States 

Census Tracts 

County Business Pattern 

Urban Areas 

Hydrological Features 

Active Lease Areas 

Offshore Blocks 

CZM 

Roads 

Shipping Routes 

Railroads 

Airport Runways 

National Priority List 

Spatial 

Location by state, county, city, lat long 

Buffers 

Nearest road, airport, pipeline, port 
203 

Appendix II 

Additional Port Facility Information
205 

PORT FACILITIES

Introduction 

Gulf Coast states provide substantial amounts of support to service the oil and gas industry 

which is so active on the Outer Continental Shelf. Many ports offer a variety of services and 

support activities to assist the industry in its ventures. Rapidly developing technology has 

resulted in changing needs. This, in turn, has placed a burden on the ports to provide the 

necessary infrastructure and support facilities in a timely manner to meet the bourgeoning 

needs of the industry. 

Previous sections have explained the network necessary to support this industry. Personnel, 

supplies and equipment must come from the land based support industry. All of those services 

must pass through a port to reach the drilling site. 

When reviewing a database established by the U.S. Army Corps of Engineers which identifies 

facilities in the Gulf of Mexico region used as service base ports for the offshore industry, it is 

astounding to see the number of private port facilities. In Louisiana alone there are 120 listed in 

this database and there are none identified in the Port Fourchon area. A survey of that area 

revealed another 27 facilities. Texas shows 84 landside support operations and there are 

others identified in Florida, Alabama, and Mississippi. Even though these are private facilities, 

they operate within the jurisdiction of a public port authority. And, to attract these operations, 

the public port must offer certain infrastructural improvements to adequately accommodate 

these operations. 

Port Profiles 

The following profiles are examples of ports who are significantly involved in offshore support. 

An effort has been made to describe their operational structure as well as to describe their 

facilities and equipment. It is this level of development that ports must sustain in order to 

provide the required land based support. 
206 

Port Fourchon

(Port Fourchon) 

P. O. Drawer 490 

Galliano, LA 70354 

(504) 632-6701 

LOCATION:

Port Fourchon (pronounced: foo-shawn) is located at the mouth of Bayou Lafourche where it 

empties into the Gulf of Mexico. It is approximately 60 miles south of New Orleans. It’s easy 

accessibility from any area in the Gulf of Mexico has made it one of the most active oil and gas 

ports on the coast. Port Fourchon’s location at the end of Louisiana Highway #1 is in the center 

of one of the richest and most rapidly developing industrial areas of the Gulf region. When the 

growth of other ports has slowed, Port Fourchon has been expanding to meet the changing 

needs of the offshore oilfield industry. 

ORGANIZATION:

The development and supervision of Port Fourchon is under the authority of the Board of 

Commissioners of the Greater Lafourche Port Commission with headquarters in Galliano 

Louisiana. It is composed of nine members who are elected to serve 6 year terms. Established 

in 1960, the GLPC Board is the only elected port authority in Louisiana and its members must 

be at least 21 years of age and residents of the 10th Ward of Lafourche Parish, Louisiana. 

The Commission regulates commerce and vessel traffic within the Port Fourchon area, owns 

land and lease facilities, establishes 24 hour law enforcement through its Harbor Police Division, 

maintains paved roads and provides facilities for governmental coordination such as the US 

Customs Service and US Coast Guard. Over its 40 year history, it has cultivated opportunities 

for businesses and steady economic growth for Port Fourchon and the surrounding area. 

GENERAL INFORMATION:

Louisiana’s only port directly adjacent to the Gulf of Mexico is located on the coast of Lafourche 

Parish and is strategically positioned to serve industrial activity associated with exploiting oil and 

gas resources offshore in the Gulf. Recent developments in offshore deepwater oil and gas 

exploration and production have brought economic benefits to both the Port and Lafourche 

Parish. Increased economic activity is associated with the provision of onshore support for the 

oil and gas industry. Port Fourchon has grown considerably since 1978 when two companies 

were located on port property. As of August 1999, there were 124 companies leasing port land. 

The physical size of the port has grown from about 25 acres in 1980 to nearly 600 acres as of 

August 1999.54

Port Fourchon is a multi-use port servicing the needs of oil and gas development, commercial 

fishing, recreation and shipping as well as providing the land base for the Louisiana Offshore 

Port Authority. The Port has the only facility in the world that offers “one-stop” shopping. It is 

 54 This paragraph is taken from: Minerals Management Service, “Technical Summary: MMS 

Publication 2001-019, Lafourche Parish and Port Fourchon, Louisiana: Effects of the Outer Continental 

Shelf Petroleum Industry on the Economy and Public Services, Part 1,” (New Orleans: U.S. Department 

of the Interior) <http://www.gomr.mms.gov/homepg/regulate/environ/techsumm/2001/2001-

019%20Fourchon.html> (July 23, 2002). 
207 

called C-Port and allows supply vessels to take on fuel, water, deck cargo, barites, cements, 

liquid muds and completion fluids all at one place, under a covered dock and in less than 24 

hours. Anywhere else, this process would take two to three days, a heavy cost to ship owners 

and platform operators. The port is comprised of approximately 600 acres and has nearly 

25,000 ft of waterfront facilities. The port has grown at a phenomenal rate due to the growth in 

the oil and gas industry and its development in the deepwater areas of the Gulf of Mexico. In 

1999 there were 124 businesses located at the port and they were increasing by one per month.

One of the most active ports in its class, Port Fourchon has been designated as one of 

Louisiana's Enterprise Zones and therefore offers many tax advantages. Its close proximity to 

the Gulf of Mexico along with its planned development and multidimensional services, make 

Port Fourchon one of the most significant oil and gas ports on the Gulf Coast. 
208 

OPERATIONAL PARAMETERS: Port Fourchon

Facility Type Physical/Operational Parameters 

Location 

Channel Access 

Land Access 

Docking 

Intermodal transfer 

(on dock) 

Warehouse 

Storage 

Yard Storage 

Inland Transport 

Cargo Throughput 

(per hour) 

On the Gulf of Mexico, at the mouth of Bayou Lafourche-about 60 miles 

south of New Orleans. 

Channel entrance: 300 ft wide by 24 ft deep; Interior Channel 300 ft 

wide by 23 ft deep; E-slip 400 ft wide by 23 ft deep; Turning Basin 800 

ft wide by 20 ft deep. 

Highway: LA 3090 2 miles to LA 1, 40 miles to U.S. 90. 

No public dock suitable for handling general cargo, numerous privately 

leased facilities. 

A large number of privately leased docks with crane service and 

loading/unloading equipment. 

A large number of privately leased warehouses. One 8,000 sq ft 

refrigerated warehouse. 

Numerous storage yards on individual leases. Improved and 

unimproved property available. 

Connection to the Intracoastal Waterway via Bayou Lafourche, Houma 

Navigation Canal and Barataria Waterway. 

Cargo throughput varies among docks. Compatibility of heavy lifts up 

to 200 tons. Numerous 150 ton options. 

Planned Expansions/Dates

The Northern Expansion Project is a 700 acre development consisting 

of 600' wide slips and over one mile of waterfront. Phase I of the 

expansion is to be complete in 2001. 

Constraints/Impediments

Two-lane highway access and lack of rail access are major 

impediments. Location on the Gulf of Mexico is an advantage but has 

limited water access to major metropolitan centers. 

Potential Vessel Service

Ocean/River vessel service, Shortsea Coastal service, Container Port 

services. 
209 

Morgan City Port Harbor and Terminal District

(Port of Morgan City) 

800 Youngs Road 

Morgan City, LA 70381 

(504) 384-0850 

LOCATION:

The Port of Morgan City is located within the community of Morgan City in St. Mary Parish. The 

port is on the east bank of the Atchafalaya River in a natural wide and deep harbor known as 

Berwick Bay. With immediate access to I-49, it is just one hour away from New Orleans, 

Lafayette and Baton Rouge. Centrally located along the Gulf coast, the Port is only 29 miles 

from the Gulf of Mexico. The Port of Morgan City has been an avenue of both domestic and 

international trade since 1957. The Atchafalaya River, the Gulf Intracoastal Waterway, and the 

Bayous Boeuf, Black, and Chene are the connections to traffic throughout the continental United 

States and abroad. The Atchafalaya River has its beginnings at the junction of Old River and 

the Red River in east-central Louisiana. Old River is a short connection between the head of the 

Atchafalaya and the Mississippi River. The Atchafalaya flows southward a distance of 135 

miles and empties into the Atchafalaya Bay. 

Traffic between points in the southwest United States and the Upper Mississippi River Valley 

saves approximately 342 miles per round trip by using the Atchafalaya River rather than the 

alternate link of the Intracoastal via the Harvey Locks at New Orleans. 

ORGANIZATION:

The Port of Morgan City was created by Act 530 of 1952 . Since 1957, it has been active in 

both domestic and international trade. It is governed by a nine member Board of 

Commissioners that are appointed by the Governor and serve for a nine year term. 

GENERAL INFORMATION:

Morgan City is the only medium draft harbor between New Orleans and Houston on the Gulf. Its 

400 ft wide channel is maintained by the U.S. Army Corps of Engineers to a constant depth of 

20 ft. Its docking and cargo handling facilities serve a wide variety of medium draft vessels. 

There are over 200 private dock facilities located in the Morgan City vicinity. These facilities 

have heavy lift, barge-mounted cranes with capacities to 5,000 tons, track cranes to 300 tons, 

and mobile cranes to 150 tons. 

The Intracoastal Waterway System and the Inland rivers of the Upper Mississippi River Valley 

reach markets in 37 U.S. states. 

Facilities include a 500 ft dock with a 300 ft extension, a 20,000 sq ft warehouse, a large 

marshalling yard, a 50 ton capacity mobile track crane and a rail spur. 
210 

OPERATIONAL PARAMETERS: Port of Morgan City 

Facility Type Physical/Operational Parameters 

Location 

Channel Access 

Land Access 

Docking 

Intermodal transfer 

(on dock) 

Warehouse Storage 

Yard Storage 

Inland Transport 

Cargo Throughput 

(per hour) 

On the Lower Atchafalaya river 18 miles from the open waters of the Gulf 

of Mexico at the intersection of the Gulf Intracoastal Waterway and the 

Atchafalaya River in St. Mary Parish, LA. 

Channel width: 400 ft - Depth 20 ft (minimum channel depth to the Gulf is 

20 ft); the Gulf of Mexico is 18 miles to the south; Access East-West is 

through the Gulf Intracoastal Waterway. 

Highway: 1.1 miles to U.S. 90; Lafayette 71 mile to the West on U.S. 90 

and New Orleans 68 miles East, Baton Rouge 71 miles north . Rail: Two 

thousand linear feet of rail spur and 1,500 linear feet of sidings connect the 

port warehouses with Burlington Northern mainline. Daily rail service is 

provided by Burlington Northern. 

Dock length: 800 ft - Width: 180 ft – 300 ft at 40 ft wide with water frontage 

of 839' on Bayou Boeuf. Suitable to handle container, general and bulk 

cargo 

Dock side mobile crane capable of lifting a fully loaded (70,000 lb.) 40 foot 

container. Three forklifts; 8,000 lb. & 10,000 lbs for warehouse use and 

one 15,000 lb. for the yard. Container crane 50 tons with 130 ft boom. 

Thirty-five ton cherry picker. Forty-ton container handler. 

3.75 acres of dock storage on the dock. A 20,000 sq ft warehouse with rail 

access. 

In addition to the 3.75 acres of on-dock storage, about 12 acres of auxiliary 

yard storage is available. 

Bulk cargo loading/unloading from/to barge 150-200 tons/hr. Bulk cargo 

transfer from/to yard from trucks and rail 100-150 tons/hr. 

Break bulk cargo transfer rate 60-80 tons/hr. 

Planned Expansion/Dates

Equipment: 30,000 lb. Forklift, three yard jockeys and six flat bed trailers 

and six chassis trailers are in the planning stage. 

Channel dredging to 35 ft. 

Constraints/Impediments

A relatively new port with new facilities recently completed. Break bulk 

cargo transfer between warehouse and dock needs use of tractors and 

trailers. Bulk cargo transfer facilities not yet available. 

Potential Vessel Services

Short sea vessel services; River/Ocean Vessel Services. 
211 

West St. Mary Port Harbor and Terminal District

(Port of West St. Mary) 

P. O. Drawer 601 

Franklin, LA 70538-0601 

(337) 828-3410 

LOCATION: 

The Port of West St. Mary is located on the Central Gulf Coast of Louisiana at Mile Marker 133 

on the Gulf Intracoastal Waterway. It is just eighteen miles from the City of Franklin, St. Mary 

Parish’s official seat of government. The complex is off U.S. Highway 90, which connects the 

Interstate highway system between Lafayette and New Orleans, and all points in the Acadiana 

region of Louisiana. 

The channel connecting the port with the Gulf Intracoastal Waterway, is -12 ft NGVD and has a 

bottom width of 150 ft to accommodate shallow draft shipping needs. 

ORGANIZATION:

The Port of West St. Mary is operated by the West St. Mary Port, Harbor and Terminal District in 

Franklin, Louisiana. It functions under the direction of a Board of Commissioners. This nine 

member body has the power to regulate the commerce and traffic of the district in a manner that 

it judges to be in the best public interest. Each Commissioner is appointed for a seven year 

term. 

GENERAL INFORMATION:

The port is a 1,500 acre complex with multi-modal transfer facilities, 6,700 ft of rail spurs, public 

loading and unloading dock with rail access, 1,350 ft of hard surface bulk headed property, and 

a public warehouse. It has highway connections with direct access to Highway 90 and 

Interstate 10. As of late 1999, the number of people employed at the Port of West St. Mary 

was about 276. 

The port offers four miles of improved water frontage with a depth that allows access to vessels 

requiring up to a 16 ft draft. The dock is reinforced by a steel sheet pile bulkhead and provides 

four berthing spaces for ocean going coastal freighters and barges. The port is serviced by rail, 

shipping vessels and trucks. Generally, it can accommodate container, general and break bulk 

cargo. 
212 

OPERATIONAL PARAMETERS: Port of West St. Mary

Facility Type Physical/Operational Parameters 

Location 

Channel Access 

Land Access 

Docking 

Intermodal transfer 

(on dock) 

Warehouse 

Storage 

Yard Storage 

Inland Transport 

Cargo Throughput 

(per hour) 

On the Gulf Intracoastal Waterway in St. Mary Parish. 

Access is by the Gulf Intracoastal Waterway by a 16 ft deep channel. 

Highway: LA Highway 83 connects the port with U.S. 90, I-49 and I-10 

Rail: 4000 ft of track Burlington Northern with La. Delta operations. 

1,300 linear ft of bulkhead available to handle general cargo. 

Mobile cranes and fork-loaders are available for cargo transfer between 

warehouse and vessel. 

65,000 sq ft of dockside warehouse is available. 

Paved storage and auxiliary yard space available - approx 7 acres. 

Direct transfer of cargo from vessel to rail and truck is possible. 

60-80 tons of break-bulk cargo per hour. 

Planned Expansion/Dates

The port has recently acquired an additional 380 acres of land adjacent 

to its location. Expansion of facilities is planned for this property. An 

additional 12,000 sq ft is being added to the existing marine fabrication 

facility. 

Constraints/Impediments

Limited market opportunities and longer voyage time. 

Potential Vessel Services

River/Ocean vessel service. 
213 

Port of Iberia District

(Port of Iberia) 

P. O. Box 9986 

New Iberia, LA 70562-9986 

(337) 364-1065 

LOCATION:

Located near the Louisiana coast in Iberia Parish, the Port of Iberia is a 2,000 acre industrial 

and manufacturing site surrounding a man-made port complex. The port has access to the Gulf 

Intracoastal Waterway and the Gulf of Mexico through its own Commercial Canal and has 

access to the Mississippi River through major ports in Baton Rouge and New Orleans. 

Generally, the port is located along the Commercial Canal approximately 9 miles north of 

Weeks Bay on the Gulf of Mexico and 4.5 miles southwest of the City of New Iberia. 

The Port Channel measures 8 miles in length from the main entrance of the Port to the Gulf 

Intracoastal Waterway. This waterway provides access to the Gulf of Mexico. Its depth is 13 ft. 

Its width is a minimum of 125 ft at the bottom and a minimum of 200 ft at the surface. 

The Port of Iberia has direct access to the Intracoastal Waterway and the Gulf of Mexico 

through the Acadiana Navigational Channel. There are no overhead restrictions or obstructions 

in the approximately 24 miles from the Port of Iberia to the Gulf of Mexico. The Acadiana 

Navigational Channel measures 16 miles in length from Gulf Intracoastal Waterway across 

Vermilion Bay to the Gulf of Mexico. It is 9 ft deep and 150 ft wide at the bottom and 200 wide 

feet at the surface. 

ORGANIZATION:

Created by Act 128 of the 1938 Louisiana State Legislature, the Port of Iberia’s territorial limits 

originally encompassed a large portion of Iberia Parish. By Act 486 of 1978, the port’s limits 

were expanded to cover most of Iberia Parish and the communities of Jeanerette and 

Loreauville. The port is governed by a seven member Board of Commissioners who serve a six 

year term. They are appointed by the parish government as well as the municipalities of 

Jeanerette and Loreauville. 

GENERAL INFORMATION:

There are 80,000 linear feet of developed water frontage at the Port of Iberia. This provides 

work sites for over 75 industries currently located and operating at the port. More than 5,000 

employees are working as welders, pipefitters, mechanics, managers, secretaries, 

programmers, accountants, and other occupations. The port’s annual payroll is in excess of 

$150 million. 

The Public Dock facilities include 3000 linear ft of bulkhead load-out area, stabilized yard, 

electric power, water, security lighting and fencing, restrooms, and parking. The total rail 

frontage is 13,000 linear ft. 

The Port of Iberia has recently expanded to incorporate an additional 170 acres of waterfront 

property. This Phase I Expansion includes land acquisition, channel excavation, bulkhead 
214 

construction, site stabilization, roadway construction, utility relocation, docking stations, 

fabrication facilities and fencing. 

Import/Export tonnage at the port includes a diversity of products and commodities; gas and oil 

pipe and supplies, agricultural products, fabrication, limestone and aggregates, steel, bulk 

concrete, barge and vessel construction, and containerized cargo. Primary emphasis is on 

fabrication to support the off shore oil and gas industry. 
215 

OPERATIONAL PARAMETERS : Port of Iberia

 Facility Type Physical/Operational Parameters 

Location 

Channel Access 

Land Access 

Docking 

Intermodal Transfer 

(on dock) 

Warehouse Storage 

Yard Storage 

Inland Transport 

Cargo Throughput 

(per hour) 

On Commercial Canal in Iberia Parish 24 miles North of the Gulf of 

Mexico, 8 miles North of Intracoastal Waterway. Mile Marker 141 on 

Intracoastal Waterway. 

Commercial Canal is 12 ft deep and over 200 ft wide, intersects the 

Gulf Intracoastal Waterway and connects to the Gulf of Mexico via 

the Acadiana Navigation Channel. 

U. S. Highway 90 (future I-49 Corridor) links the Port with I-10. LA 

Highways 182, 14, and 83 also serve the Port. Rail access to the 

Port is provided by Burlington Northern-Sante Fe. 

800 ft Public Barge Dock available for handling general cargo. 

Mobile cranes, forklifts, heavy hauling trucks, and other cargo 

handling equipment available. 

The Port is a 2,000 acre industrial and manufacturing facility with 100 

industries located and operating. 

Stabilized yard storage available. 

Inland transport available. 

50-75 tons of break-bulk cargo per hour. 

Planned Expansion/Dates

170 acre waterfront expansion completed on 8/1/00. One mile of 

new channels. Upgrading of public Port facilities is in progress. 

Constraints/Impediments

12 ft water depth. 

Potential Vessel Services

Oil/Gas Supply Vessel Service; Small Cruise Ship Terminal. 
216 

Port of New Orleans 

P. O. Box 60046 

New Orleans, LA 70160 

(504) 522-2551 

LOCATION: 

Ideally located at the mouth of the Mississippi River, the Port of New Orleans is America’s 

gateway to the global market. New Orleans has been a center for international trade since 1718 

when it was founded by the French. 

ORGANIZATION: 

The Port of New Orleans is governed by a seven member Board of Commissioners. The Board 

sets policies and regulates the traffic and commerce of the Port. The Commissioners are 

unsalaried and serve five-year staggered terms. The governor of Louisiana appoints board 

members from a list of three nominees submitted by 19 local business, civic, labor, education 

and maritime groups. The seven person board reflects the three-parish jurisdiction of the 

Board. Four members are selected from Orleans Parish, two from Jefferson Parish and one 

from St. Bernard Parish. 

GENERAL INFORMATION: 

Valued at more than $700 million, the port’s facilities include 22 million square feet of cargo 

handling area and more than 6 million square feet of covered storage area. In the last 10 years, 

the Port of New Orleans has invested nearly $500 million in new facilities. Improved breakbulk 

and container terminals feature new multipurpose cranes, expanded marshalling yards and a 

new roadway to handle truck traffic. A new container terminal is under construction at Napoleon 

Avenue. The state-of-the-art complex will feature a new 1,739 linear ft wharf and 44-acre 

marshalling area. The terminal is scheduled to open in the fourth quarter of 2002. 

The port’s facilities accommodate an average of 2,400 vessel calls each year. The average 

general cargo volume is 11.2 million tons (1995-99), with a record 14.1 million tons in 1998. 

New Orleans is one of America’s leading general cargo ports and has the USA’s top market 

share for import steel, natural rubber, plywood and coffee. 

New Orleans is the only deepwater port in the United States served by six class one railroads. 

In addition to excellent rail service, the Port of New Orleans is served by 70 steamship lines, 16 

barge lines, and 75 truck lines. 
217 

OPERATIONAL PARAMETERS: Port of New Orleans 

 

Facility Type Physical/Operational Parameters 

Location 

Channel Access 

Land Access 

Docking 

Intermodal transfer 

(on dock) 

Warehouse Storage 

Yard Storage 

Inland Transport 

Cargo Throughput 

(per hour) 

Cruise Terminals 

On the Mississippi River between mile 81.5 AHP and mile 114.9 AHP. 

On the Inner Harbor Navigation Canal on the Mississippi River Gulf Outlet 

(MRGO) 

Deep draft 45 ft in the main channel with a minimum width of 2,000 ft. 

Thirty-six feet in the MRGO with a bottom width of 500 ft. 

Highway access to I-10 and I-55. 

Rail: CSX, KCS, Canadian National, Norfolk Southern, Union Pacific, and 

New Orleans Public Belt Railroad. 

22 miles of water frontage, wharves and terminals. For container cargoes, 

the multi-berthed France Road Terminal is equipped with container cranes. 

Multi-purpose cranes at the Nashville Ave. terminal. Modern container 

cranes and all cargo handling equipment to handle container cargo. 

Dockside cranes and cargo handling equipment are available to handle 

break-bulk cargo at the general cargo terminals. 

The port offers more that 22 million sq ft of cargo handling area within its 

various facilities. 

All cargo storage areas are served by rail, and have adequate open yard 

areas. 

Advanced container cargo handling system with dockside cranes and 

handling at marshalling areas. Break-bulk and Neo-bulk cargo handling 

equipment. 

Varies by operation and terminal location. 

Cruise Terminals at Julia Street Wharf and Robin Street Wharf. 

Planned Expansion/Dates 

A new container terminal is under construction and will be known as the 

Napoleon Avenue Container Yard. It will be operational by February 2002. 

Constraints/Impediments 

Market development in terms of improved services, networking with 

Mexican businesses, attention to small shippers. 

Potential Vessel Services 

Fast-Ferry Trailer Service; River/Ocean vessel service; Shortsea Coastal 

Service and refrigerated vessel service. 
218 

Port of Panama City 

P. O. Box 15095 

Panama City, FL 32406 

(850) 769-7000 

LOCATION: 

Located on US 98 in Bay County adjacent to the Hathaway Bridge connecting Panama City to 

Panama City Beach. This is a deepwater port, along Florida's panhandle, specializing in breakbulk cargo plus some dry bulk products. 

ORGANIZATION: 

The port is governed by the Panama City Port Authority whose mission is to maintain, enhance 

and promote the economic development of Panama City and Bay County through the continued 

development of the Port of Panama City and its Industrial Park. There are 5 Commissioners 

who serve on the Port Authority and each is appointed to a five year term. 

GENERAL INFORMATION: 

Port Panama City is a relatively young port. When it was established in 1967, it had one 

deepwater berth and one 42,000 square foot warehouse. Currently the Port has five deepwater 

berths consisting of 2,590 linear ft with a 32-ft draft, 600 linear ft of barge facilities and 470,000 

square ft of warehousing space. The Port is equipped with modern facilities to load and unload 

product from truck, rail, barge, container, RoRo vessel or deepwater vessel traffic. The Gulf 

Intracoastal Waterway is located adjacent to the Port and offers intracoastal shipment via barge. 

The maritime community of Panama City consists of various professionals such as 

longshoremen, steamship agents, freight forwarders, customhouse brokers, and others 

necessary to support a modern transportation facility. 

Primary exports include linerboard, woodpulp, machinery, and miscellaneous general cargo; 

Imports are steel plate, steel coils, lumber, and liquid bulk. Tonnage throughput for FY 01/02 is 

projected to be 1.1 million tons. 

The Port of Panama City has offered Foreign-Trade Zone status since November 11, 1981 

when FTZ #65 came into existence. At that time the general-purpose foreign-trade zone was 

activated and made available to the public. On March 1, 1982, the second phase of FTZ #65 

was activated. This phase contains Berg Steel Pipe Corporation. 
219 

OPERATIONAL PARAMETERS: Port of Panama City 

 

Facility Type Physical/Operational Parameters 

Location 

Channel Access 

Land Access 

Docking 

Intermodal transfer 

(on dock) 

Warehouse 

Storage 

Yard Storage 

Inland Transport 

Cargo Throughput 

(per hour) 

On the Gulf of Mexico in Bay County, Florida along US 98. It is 

adjacent to the Gulf Intracoastal Waterway. 

Access is through a 32 ft channel. 

Rail service is provided by Bay Line, a class III railroad that runs 

between Dothan, AL and the port. It connects with CSX and Norfolk 

Southern. 

3,100 linear ft of dock space. 

Gantry crane - heavy lift capacity 45 mt at 155 ft out from center point, 

Ro/Ro berths. 

approximately 470,000 sq ft of covered warehouse area. 

300,000 sq ft of paved open storage. 

Cargo leaves the port by the Gulf Intracoastal Waterway, by rail or 

truck. 

Varies with commodity and facility used. 

Planned Expansion/Dates 

Currently in the process of a South Dock extension for 162,000 sq ft 

equipped with 2 rail spurs and a 300 ton capacity lift; In 2001 plan to 

deepen West Dock to 32 ft. Plan to widen the Ship Channel to 150 ft. 

Constraints/Impediments 

Located at a heavily traveled city intersection with no adequate access 

to I-10 which is about 50 miles north. 

Potential Vessel Services 

Shortsea Coastal Vessels. 
220 

Alabama State Docks 

(Port of Mobile) 

P.O. Box 1588 

Mobile, AL 36633 

(334) 441-7001 

LOCATION: 

With its deepwater seaport facilities at the Port of Mobile, the Alabama State Docks is 

conveniently located on the central U.S. Gulf and is closer to open water than any other major 

port on the Gulf. There has been commerce in and out of the Port of Mobile since the early part 

of the 17th Century. It was not until 1826 that the U.S. Congress authorized money for the 

development of a navigable channel in Mobile Bay. The current navigation channel maintained 

by the U.S. Army Corps of Engineers provides a safe navigational depth of 45 feet from the Gulf 

of Mexico to the mouth of the Mobile River. 

Four trunkline railroads serve the port, which is situated at the intersection of two major 

interstate highways. The state offers 1,500 miles of navigable inland barge routes and is served 

by the Tennessee-Tombigbee Waterway which connects 16,000 miles of interstate barge lanes 

with the Port of Mobile. 

ORGANIZATION: 

For the first two hundred years of its existence, the Port of Mobile did not have a central 

organization to guide the development and operation of the port. In 1920, the Alabama 

Legislature submitted a constitutional amendment to the people to develop Alabama's seaport 

with state financial assistance. The amendment was passed in 1922 under Governor Thomas E. 

Kilby, and the State Docks Commission was established with power to build, operate and 

maintain wharves, piers, docks, quays, grain elevators, cotton compresses, warehouses and 

other water and rail terminals, structures and facilities. Since that time, the Alabama State 

Docks has been a part of Alabama State government and functions as an independent 

department with a board of directors. Today, the Department operates as a self-supporting 

enterprise agency of the Executive branch of state government. 

GENERAL INFORMATION: 

About 375 employees operate, maintain and market these facilities. In 1999, the Port of Mobile 

was the 14th largest port in the nation in total tonnage. The economic impact to the State of 

Alabama was over $3 billion statewide. Tax payments of $467 million were made from activities 

in the International Trade sector. And most importantly, the Alabama State Docks supports the 

jobs of more than 118,000 Alabamians. 

The Alabama State Docks offers 29 general cargo berths with about 4 million sq ft of covered 

storage space and an additional 4 million sq ft of open storage area adjacent to piers and 

tracks. The Docks' general cargo capabilities have been enhanced in recent years, with about 

$80 million invested in capital improvement projects. New state-of-the-art wharves and 

warehouses include the 360,000-sq ft Forest Products Terminal at Pier C, the 152,000-sq ft 

Blakeley Terminal on the east bank of the Mobile River and the Steel & Heavy Lift Operations 

Berth at Pier North C, to warehouses with a combined space of 253,000 square feet, a new pier 

for Roll On-Roll Off operations, and a concreted marshaling area. 
221 

The State Docks also provides a container port operation and other RO/RO berths 

accommodating some of the largest ocean-going vessels afloat. The inner harbor is accessible 

to ships drawing 40 ft of water. The outer harbor is dredged to accommodate vessels drawing 

45 ft. 
222 

OPERATIONAL PARAMETERS: Port of Mobile 

 

Facility Type Physical/Operational Parameters 

Location 

Channel Access 

Land Access 

Docking 

Intermodal transfer 

(on dock) 

Warehouse 

Storage 

Yard Storage 

Inland Transport 

Cargo Throughput 

(per hour) 

The Alabama State Docks is located on the Mobile River. This river is 

formed some 45 miles north of the city with the joining of the Alabama 

and Black Warrior/Tombigbee Rivers. 

The U.S. Army Corps of Engineers maintains the navigation channel to 

a depth of 45 ft from the Gulf of Mexico to the mouth of the Mobile 

River. 

Highway: approximately 2 miles from I-10. 

Rail: Terminal Railway operates on 75 miles of track using eight 

locomotives to transport cargo to and from piers, warehouses and 

terminals. It connects to four mainline railroads: Burlington 

Northern/Santa Fe; CSX; Illinois Central, and Norfolk Southern. 

35 berths available for handling cargo (29 general cargo and 6 bulk). 

more that 2.2 million sq ft of covered storage. 

McDuffie - 125 acres; Main docks cover 500+acres (about 100 is 

prepared storage area); Middle Bay has 200 acres; Choctaw Point has 

276 acres. 

consists of 16,000 miles of navigable inland waterways through the 

Tenn-Tom Waterway. 

varies according to commodity and dock. 

Planned Expansion/Dates 

Currently awaiting legislative approval for a $100 million appropriation 

that would fund a container intermodal facility 

Constraints/Impediments 

The port has excellent land and water access. The only impediment is 

financial limitations. 

Potential Vessel Services 

New liner services have been attracted to the port. 
223 

Port of Houston Authority 

(Port of Houston) 

P. O. Box 2562 

Houston, TX 77252-2562 

(713) 670-2429 

LOCATION: 

The Port of Houston has been an operational deep-draft port since 1914. It’s central location on 

the Gulf Coast has helped it to become the world’s 8th largest port. The port ranks first in the 

United States in foreign waterborne commerce and second in total tonnage. It consists of a 

25-mile-long complex of diversified public and private facilities located on the Houston Ship 

Channel just a few hours' sailing time from the Gulf of Mexico. 

Ample truck, rail and air connections allow shippers to economically transport their goods 

between Houston and inland points. 

ORGANIZATION: 

The Port of Houston Authority owns and operates eight public facilities along the Houston Ship 

Channel and is the channel's official sponsor. The Houston Ship Channel extends 50 miles 

inland and links the City of Houston with the Gulf of Mexico. The Authority is a navigation 

district and a political subdivision of the State of Texas. 

The seven-member Port of Houston Commission is the governing body for the Port of Houston 

Authority. Each member is appointed for a 2-year term. The City of Houston and the Harris 

County Commissioners Court each appoint two commissioners. These two governmental 

entities jointly appoint the chairman of the Port Commission. The Harris County Mayors & 

Councils Association and the City of Pasadena each appoint one commissioner. 

GENERAL INFORMATION: 

Houston lies within close reach of one of the nation's largest concentrations of consumers. More 

than 17 million people live within 300 miles of the city, and approximately 60 million live within 

700 miles. 

Since the Port of Houston first opened to deep-water vessels in 1914, Houstonians have 

recognized that their port is an important economic catalyst. The port is one of the most 

significant sources of jobs and revenue in the community. 

Each year more than 6,400 vessels call at the port. The 1997 figures show the port's public and 

private marine terminals generate $7.7 billion in business revenues annually. In addition, direct 

and related jobs associated with port activity totaled 204,520 in Texas and another 436,500 

nationwide. Direct jobs are those generated by the companies providing support services to the 

cargo handling and vessel-related services of the port. Related jobs are those created locally 

and throughout the regional economy due to purchases of goods and services by those directly 

associated with port activity. Of the 75,487 direct jobs affiliated with Port of Houston activity, 

approximately 90% are held by Houston and Harris County residents. Related jobs totaled 

129,033. Research shows the port also generates $525 million dollars annually in state and 

local taxes. 
224 

OPERATIONAL PARAMETERS: Port of Houston 

 

Facility Type Physical/Operational Parameters 

Location 

Channel Access 

Land Access 

Docking 

Intermodal transfer 

(on dock) 

Warehouse 

Storage 

Yard Storage 

Inland Transport 

Cargo Throughput 

(per hour) 

Located in the City of Houston along the 25-mile complex known as the 

Houston Ship Channel. 

The Houston Ship Channel is accessed from the Gulf through 

Galveston Bay - depth 36 ft to 40 ft. 

All terminals have near access to Interstate highways. All terminals 

have rail access. 

Barbours Cut Terminal-6,000 ft; Turning Basin Terminal-20,000 ft; 

Woodhouse Facility-1,910 ft; Jacintoport-1,830 ft; Public Grain 

Elevator-600 ft; Bulk Materials Handling Plant 650 ft; Care Terminal1,118 ft; Galveston Container Terminal-1,436 ft. 

Container cranes-30/50 ton capacity, lash dock, Ro/Ro ramp, 500 ton 

barge crane, two container gantry cranes, 20-300 ton shore cranes; 

Direct discharge of cargo, to truck or rail; Container cranes-40/60 ton 

capacity. 

Over 2,000,000 sq ft of covered storage. 

Over 300 acres of open storage and marshalling area. 

Inland transport is by rail and truck and the GIWW. 

Varies with commodity and terminal being used. 

Planned Expansion/Dates 

45' foot deep channel being constructed; planned expansion of 

container facilities; expansion and renovation of facilities at Turning 

Basin Terminals, Barbours Cut, Houston Ship Channel, Bulk Materials 

Handling Plant and Bayport. 

Constraints/Impediments 

Potential Vessel Services 

Potential cruise market. 
225 

Port of Victoria

Port Victoria, TX took its place as a port in 1968 when the 35-mile Barge Canal to Victoria was 

completed. The Port of Victoria in Texas is a joint effort supported by the Victoria County 

Navigation District and the West Side Calhoun County Navigation District. Major products 

transferred in at the port include liquid and dry bulk, general and project cargos. 

The Port turning basin area is situated on over 400 acres and is served by rail and 4 lane 

divided highways. A 350 ft transit dock and a lighting system allow for 24 hour/7 day a week 

cargo operations. There are 20 mooring sites and 17,000 sq ft of shed space and over 3 acres 

of ground storage areas. A 7,300 sq ft office and storage building is also located at the turning 

basin. 

The Victoria Barge Canal is a 35-mile long waterway that connects the Turning Basin in Victoria 

to the Gulf Intracoastal Waterway. The distribution advantage of the canal is its link with the 

Gulf Intracoastal Waterway and the major shipping lines that service ports on the Texas coast. 

The GIWW not only links the Gulf Coast from Brownsville, TX to Apalachee Bay, FL but also the 

Mississippi River, Ohio River and their connecting canals and river basins. This links Victoria to 

Minneapolis/St. Paul, Chicago and the Great Lakes, Pittsburgh, PA and Knoxville, TN to 

mention only a few locations on the 26,000 mile Inland Waterway system. 

In March 2002, a $50 million widening and deepening project was completed. This partnership 

with the U.S. Army Corps of Engineers produced new channel dimensions of 12 ft in depth and 

125 ft in width (the operational width is 75 ft and an air draft of 50 ft). The original dimension of 

the canal was a depth of 9 ft and width of 100 ft. This expansion will allow for larger vessels 

and heavier loads to access the Canal. 

Also newly created at the Port of Victoria is a multi-modal industrial park. The Park is located 

within a free trade zone and a Texas Enterprise Zone. The Navigation Districts have the ability 

to build to suit and tailor a package specific to customer facility and transportation needs. The 

Port of Victoria is a center for the petrochemical, construction and steel fabrication industries. 

The most recent success in the Industrial Park is a 36,000 sq ft “build to suit” metal fabrication 

unit complete with 30-ton overhead cranes for a power generation manufacturing customer. 

The company will employ over 100 people and have an economic impact of over $25 million 

annually. 

Companies that benefit from the barge canal and industrial park include DuPont, The Fordyce 

Company, BP Chemical, Seadrift Coke, Dow Operations, United Agri Products, and Technicoat. 

The Barge Canal generates over 11,000 jobs with a personal income of $364.2 million. 
226 

Port of Galveston

Located on the upper Texas coast at the mouth of Galveston Bay, 9.3 miles from the open sea, 

the Port of Galveston hosts facilities to handle all types of cargo including containers, dry and 

liquid bulk, breakbulk, RO/RO, refrigerated and project cargoes and cruise passengers. The 

Galveston channel has an authorized minimum depth of 40 ft and is 1,200 ft wide at its 

narrowest point. 

The Port owns and operates for hire public wharves, transit sheds, open and covered storage 

facilities, warehouses and freight handling facilities. The majority of land and facilities are 

leased. Facilities include: 

TERMINAL RAILWAY / Operator: Galveston Railroad, L.P. 

• Provides rail connections to the Burlington Northern Santa Fe Railroad and the Union 

Pacific Railroad System 

PIER 10 CONTAINER TERMINAL / Operator: Port of Houston Authority 

• Import and Export Containers 

• 1,346-ft, 2-berth dock 

• Water depth of 40 ft 

• 4 container cranes 

• 38-acre terminal 

• On-terminal rail ramp 

• Truck and rail served 

PIER 14 MARINE REPAIR FACILITY / Operator: Smith-Hamm, Inc. 

• Maintenance and repair of vessels and drilling rigs 

• 1,509 ft of berthing space 

• Water depth of 24 ft to 25 ft 

• 35,000 sq ft of backup space 

PIER 16-18 FRESH FRUIT AND PRODUCE / Operator: Del Monte Fresh Produce 

• Import fresh fruit, primarily bananas 

• 1,203-ft, 2-berth dock 

• Water depth of 34 ft 

• 65,000 sq ft of refrigerated warehouse space 

• Truck served 

PIER 19 MOSQUITO FLEET / Operator: Marina for Commercial Fishing Boats 

• Commercial Shrimping and Fishing Boats 

• Deepsea Party Boats 

• Wholesale Seafood Businesses 

• Restaurants 

PIER 19-22 WINDOW ON THE WATERFRONT / Tourist-Oriented Facility 

• Ocean Star Drilling Rig Museum 

• Shops 

• Restaurants 
227 

• Theaters and art galleries 

• Waterfront Inn 

• 1877 Iron Barque ELISSA 

• Restaurants 

• Texas Seaport Museum 

PIER 25 CRUISE SHIP TERMINAL / Operator: Port of Galveston 

• 800-ft berth 

• Water depth of 30 ft 

• Efficient passenger and luggage handling 

• Total PAX Embarkation Area - 44,000 sq ft 

• Total PAX Disembarkation Area - 48,000 sq ft 

• Total Cruise Terminal Area - 132,000 sq ft 

• Supplier Staging Area - 53,000 sq ft 

• Future Interior Expansion Area - 90,000 sq ft 

PIER 30-32 EXPORT GRAIN ELEVATOR / Operator: ADM/Farmland Inc. 

• Export bulk grain 

• 1,000-foot berth 

• Water depth of 40 ft 

• 3,000,000 bushel storage capacity 

• Railcar unloading capacity of 1,600 MT 

• Vessel loading capacity of 2,000 MT per hour 

• Truck and rail served 

PIER 34 MANUFACTURING FACILITY / Operator: Deep Flex 

• Manufacturing of flexible pipe for offshore oil and gas industry 

• Export of flexible pipe 

• Water depth of 40 ft 

• 44,530 sq ft warehouse space 

• Truck served 

PIER 34 IMPORT/EXPORT VEHICLE HANDLING FACILITY / User: "K" Line 

• Importation of vehicles - Primarily agricultural and construction equipment 

• 632 ft berth 

• Water depth of 38 ft 

• Adjacent warehouse space of 184,795 sq ft 

• Truck and rail served 

PIER 35 MANUFACTURING FACILITY / Operator: EnviroLife, Inc. 

• Manufactures floral foam used in the fresh flower marketing business 

PIER 35-36 IMPORT SUGAR TERMINAL / Operator: Imperial Sugar Company 

• Import bulk sugar 

• 642-ft berth 

• Water depth of 36 ft 

• 30,000 ton storage capacity 

• 2 shipside gantry cranes 
228 

• Truck and rail served 

PIER 37 IMPORT/EXPORT VEHICLE HANDLING TERMINAL / Operator: Wallenius 

Wilhelmsen Lines 

• Import vehicles primarily agricultural and construction equipment 

• 1,160-ft berth 

• Water depth of 34 ft 

• 75,000 sq ft warehouse 

• 12 acres of marshalling area 

• Truck and rail served 

MARINE REPAIR FACILITY / Operator: First Wave/Newpark Shipbuilding - Pelican Island, Inc. 

• Maintenance and repair of vessels and drilling rigs 

• 110-acre facility 

• Water depth of 25 ft to 40 ft 

• 5000 ton dry dock 

• Repair, modifications, construction, engineering and environmental services to the marine 

and offshore industry 

• Fabrication areas and equipment to support modular construction 

• Pier space and services to accommodate all types of floating structures 
229 

Appendix III 

Description of OCSGEN 
231 

Technical Description of OCSGEN 

OCSGEN calculates volumes of waste generated by OCS activities that must be transported 

back to shore and handled by land-based waste management facilities from input estimates of 

average rates of waste generation and level of activity. In its current phase, broad estimates 

about the rates of waste generation are applied across the entire Gulf Coast OCS to arrive at 

gulf-wide estimates for waste generation over a 35-year planning period. The model allows the 

user to model more precisely the specifics of a particular lease sale, technology assumption, or 

rule by changing the inputs to reflect more accurate scenario-specific waste generation rates 

and activity rates. 

OCSGEN allows for waste generation from either an active drilling rig, an active producing well, 

a completion, or a workover. Each activity event is assigned a waste generation rate such as 

barrels per well drilled, tons of MSW per active well per year, tons of MSW per active drilling rig 

per year, and so forth. These rates are found as inputs and the rows labeled as such. 

 

For the Gulf-wide estimates, OSCGEN allows two different cases for each of three planning 

regions. Although these could be combined into as many as six scenarios, in the version 

presented here only the “High” and “Low” exploration scenarios for each of the three planning 

areas are presented. “High” and “Low” scenarios each contain the same waste generation rate 

assumptions. For a given exploration scenario, “High” and “Low” could just as easily be defined 

to represent a range of waste generation rates, resulting in a range of total waste generation 

volumes for the analysis at hand. 

OCSGEN waste generation rates presented here represent conclusions based on professional 

judgment but draw on observations collected from the following sources. 

• regulators 

• trade associations 

• generators 

• waste management companies 

• literature reviews 

The subjective conclusions relied on reconciling numerous sources into a single-point estimate. 

The estimates were not developed from a random sample with statistical precision due to 

limitations of budget and survey techniques. Regardless of how accurate the waste generation 

rate estimates may ultimately prove to be, the nature of oil and gas operations makes 

generalizations of Gulf-wide activity to a single well or field difficult. Any given well or particular 

type of well may vary widely from the mean. Further data gathering efforts by future researchers 

may well introduce valid statistical measurement into the quantification of waste generation 

rates. We must point out, however, that changes in exploration and production technology and 

regulation may do their part to render obsolete within a few years even an accurate estimate 

made at a given point in time. 
232 

Eastern Planning Area Central Planning Area 

Western Planning 

Area 

Low High Low High Low High 

Oil, bbls. 75000000 140000000 9250000000 12350000000 1485000000 

273500000

0 

Gas, MCF 1800000000 2710000000 82650000000 1.13475E+11 37780000000 54225000000 

BOE 394715808.2 621349911.2 23930284192 32505417407 8195479574 12366438721 

 

Existing wells (total) 12839 12839 2105 2105 

Oil wells 5906 5906 397 397 

Gas wells 5315 5315 1487 1487 

 

Rigs years required 

to drill 47.8 204.7 1831.3 3212.0 1261.9 2424.4 

 

Well Activity 

Exploration and 

delineation wells 80 420 3520 5020 1805 3265 

Development wells 135 500 4710 9415 1685 3440 

Oil wells 55 305 2710 5470 285 830 

Gas wells 80 195 2000 3945 1400 2610 

Workovers and 

completions 459 1700 113300 126300 20000 24600 

 

Production 

Structures 

Existing structures 0 0 3454 3454 509 509 

Number installed 15 55 685 1320 270 495 

Structure removals 

using explosives 2 8 336 487 81 123 

Total structure 

removals 6 21 490 720 120 190 

Producing wells per 

structure 9.00 9.09 6.88 7.13 6.24 6.95 

 

Method of Oil 

Transportation 

Percent Piped 90% 96% 95% 94% 

Percent Barged 1% 1% 2% 

Percent Tankered 10% 3% 4% 4% 

Length of installed 

pipelines (km) 25,270 35,200 4,140 5,770 

Length of installed 

oil pipelines (km) 5,260 9,950 790 1,510 

Length of abandoned 

pipelines (km) 3,590 6,390 400 720 

Length of removed 

pipelines (km) 26 380 4 70 

 

 
233 

Blowouts 25 29 79 124 27 50 

Service-vessel trips 41,000 137,000 8,576,000 10,201,000 1,683,000 2,229,000 

Helicopter trips 4,787,000 5,754,000 15,784,000 24,298 9,281 13,692 

 

Waste transported 

ashore 

 Barrels per exploratory well 

drilled: 

Mud 7,861 7,861 7,861 7,861 7,861 7,861 

Cuttings 2,681 2,681 2,681 2,681 2,681 2,681 

 Barrels per development well 

drilled: 

Mud 5,808 5,808 5,808 5,808 5,808 5,808 

Cuttings 1,628 1,628 1,628 1,628 1,628 1,628 

 Barrels per 

completion/workover

: 

Fluids 150 150 150 150 150 150 

 

Drilling, completion 

and 

workover waste 

discharged 

 Barrels per 

exploratory well: 

Mud 7,861 7,861 7,861 7,861 7,861 7,861 

Cuttings 2,681 2,681 2,681 2,681 2,681 2,681 

 Barrels per 

development well: 

Mud 5,808 5,808 5,808 5,808 5,808 5,808 

Cuttings 1,628 1,628 1,628 1,628 1,628 1,628 

Barrels per 

completion/workover 

Fluids 100 100 100 100 100 100 

 

Produced waste 

discharged 

Barrels of water per 

day/oil well 450 450 450 450 450 450 

Barrels of water per 

day/gas well 68 68 68 68 68 68 

Produced sand, 

barrels per bbl of oil 0.005 0.005 0.005 0.005 0.005 0.005 

 

Total waste 

discharged per year 

Produced water from 

oil wells 3,513,125 19,481,875 173,101,250 349,396,250 18,204,375 53,016,250 

 
234 

Produced water from 

gas wells 717,022 1,747,742 17,925,556 35,358,158 12,547,889 23,392,850 

Workover/completio

n fluids 1,275 4,722 314,722 350,833 55,556 68,333 

Produced sand 54,822 86,299 3,323,651 4,514,641 1,138,261 1,717,561 

 

Waste volumes 

transported ashore 

 Barrels per 

exploratory well: 

Mud 1,595 1,595 1,595 1,595 1,595 1,595 

Cuttings 386 386 386 386 386 386 

 Barrels per 

development well: 

Mud 444 444 444 444 444 444 

Cuttings 108 108 108 108 108 108 

 Barrels per 

completion/workover

: 

Fluids 200 200 200 200 200 200 

 

Drilling mud 187,540 891,900 7,705,640 12,187,160 3,627,115 6,735,035 

Cuttings 45,460 216,120 1,867,400 2,954,540 878,710 1,631,810 

Completion/workove

r fluid 9,180 34,000 2,266,000 2,526,000 400,000 492,000 

Planning period total 242,180 1,142,020 11,839,040 17,667,700 4,905,825 8,858,845 

 

Average per year 6,727 31,723 328,862 490,769 136,273 246,079 

 

MSW, tons per 

rig/year 192 192 192 192 192 192 

MSW, tons per 

producing well/year 

 

0.64 

 

0.64 

 

0.64 

 

0.64 

 

0.64 

 

0.64 

 

Total MSW 

generated (tons) 

From established 

production 0 0 82802.34519 82802.34519 23414 23414 

From new 

production 4866.628996 17109.94796 1041043.271 1175981.621 193220.520 245678.989 

From drilling 9185.467372 39305.25573 351611.1464 616708.0071 242283.556 465476 

Total MSW 14052.09637 56415.20369 1392654.418 1792689.628 435504.076 711154.989 

 

Average MSW per 

year 390.3360102 1567.088991 38684.84494 49796.93411 12097.3354 19754.3052