OCS Study

BOEM 2012-102

MAG-Plan 2012

Economic Impact Model for the 

Gulf of Mexico-Updated and Revised Data

U.S. Department of the Interior

Bureau of Ocean Energy Management

Gulf of Mexico OCS Region
U.S. Department of the Interior

Bureau of Ocean Energy Management

Gulf of Mexico OCS Region

OCS Study

BOEM 2012-102

MAG-Plan 2012

Economic Impact Model for the 

Gulf of Mexico-Updated and Revised Data

Authors 

Maureen F. Kaplan

Sara Kauffman

Christiana Marsden

Prepared under BOEM Contract

M09PC00038

by

Eastern Research Group, Inc.

110 Hartwell Avenue

Lexington, MA 02421

Published by

New Orleans

March 2013
iii

DISCLAIMER

This report was prepared under contract between the Bureau of Ocean Energy Management 

(BOEM) and Eastern Research Group, Inc. This report has been technically reviewed by the 

BOEM and has been approved for publication. Approval does not signify that the contents 

necessarily reflect the view and policies of the BOEM, nor does mention of trade names or 

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

from review and in compliance with BOEM editorial standards. 

R E POR T AVAIL AB ILITY

This report is available on CD from the Bureau of Ocean Energy Management, Gulf of 

Mexico OCS Region, for $15.00, and free of charge as a pdf file downloaded from the BOEM 

Web site. Copies can also be viewed at selected Federal Depository Libraries. The addresses are 

listed below.

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

OCS Study BOEM 2012-0xx. To download a pdf copy, use the Environmental Studies Program 

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

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

U.S. Department of the Interior 

Bureau of Ocean Energy Management

Gulf of Mexico OCS Region 

Public Information Office (GM 217G ) 

1201 Elmwood Park Blvd. 

New Orleans, Louisiana 70123-2394 

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

Fax: (504) 736-2620 

U.S. Department of Commerce 

National Technical Information Service

5301 Shawnee Rd. 

Springfield, Virginia 22312 

Phone: (703) 605-6000, 1-800-553-6847 

Fax: (703) 605-6900 

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

CITATION

Eastern Research Group, Inc. 2012. MAG-PLAN 2012: Economic Impact Model for the Gulf of 

Mexico—Updated and Revised Data. U.S. Dept. of the Interior, Bureau of Ocean Energy 

Management, Gulf of Mexico OCS Region, New Orleans, LA. OCS Study BOEM 2012-

102. 143 pp. 
v 

AC K NOWL E DG ME NTS

Eastern Research Group, Inc. would like to thank Michael Barton, Sindey Chaky, Kim 

Coffman, Thierry DeCort, Sarah Peters, Thomas Riches, Kristen Strellec, and Michelli Uli, all of 

BOEM, for their helpful comments and assistance with preparing this report. 
vii 

TABLE OF CONTE NTS

LIST OF FIGURES ..................................................................................................................... ix

LIST OF TABLES ..................................................................................................................... xi

1.0Executive Summary .................................................................................................................. 1

1.1 Purpose ...................................................................................................................... 1

1.2 Report Organization ....................................................................................................... 2

2.0 Introduction ...................................................................................................................... 3

2.1 History ...................................................................................................................... 3

2.2 Basic Concepts ............................................................................................................... 4

2.2.1 Direct, Indirect, and Induced Effects ..................................................................... 4

2.2.2 Activity Types/Activity Functions ........................................................................ 4

2.3 Activity Functions in MAG-PLAN ................................................................................ 5

2.3.1 Prerequisite IMPLAN Analyses ........................................................................... 5

2.3.2 Setting Up MAG-PLAN ....................................................................................... 7

2.3.3 Sample MAG-PLAN Calculation Flow ................................................................ 7

2.3.4 Stage 2 Calculations ............................................................................................. 9

2.4 Revenue Functions in MAG-PLAN ............................................................................... 9

3.0 Industry Expenditures .............................................................................................................. 10

3.1. Drilling and Associated Geological and Geophysical Prospecting .............................. 10

3.1.1 Exploration Wells ................................................................................................ 11

3.1.2 Nonproduction Development Wells .................................................................... 13

3.1.3 Increased Costs Due to New Regulatory Requirements ..................................... 15

3.1.4 Productive Development Wells ........................................................................... 15

3.1.5 Final Well Costs in MAG-PLAN 2012 ............................................................... 17

3.2 Geological & Geophysical (G&G) Prospecting ........................................................... 18

3.3 Production System Fabrication and Installation ........................................................... 20

3.4 Onshore Gas Processing Facility .................................................................................. 22

3.5 Pipeline Construction ................................................................................................... 23

3.6 Platform Decommissioning .......................................................................................... 23

3.7 Production O&M .......................................................................................................... 25

3.8 Onshore Gas Processing O&M .................................................................................... 26

3.9 Pipeline Operations and Maintenance .......................................................................... 26

3.10 Sector Allocation For New Activity Functions ............................................................ 28

4.0Labor Cost Percentages ........................................................................................................... 28

4.1 Activity Functions with Composite Labor Shares ....................................................... 28

4.1.1 Exploratory Well Drilling ................................................................................... 28

4.1.2 Nonproductive Development Well Drilling ........................................................ 30

4.1.3 Productive Development Well Drilling ............................................................... 31

4.1.4 Comparison of Labor Share Estimates for Well Drilling .................................... 33

4.1.5 Production O&M ................................................................................................. 33
viii

4.2 Labor Shares for Remaining Activities ........................................................................ 39

5.0Onshore Distributions .............................................................................................................. 40

5.1 Onshore Areas of Interest ............................................................................................. 42

5.2 Top-Down Approach .................................................................................................... 46

5.2.1 The ROW ............................................................................................................. 46

5.2.2 Rest of United States ........................................................................................... 47

5.2.3 Texas, Louisiana, Mississippi, Alabama, and Florida ......................................... 47

5.2.4 Separating Each State Into “GOM” and “Rest of” Regions ................................ 48

5.2.5 Separating State GOM Regions Into Individual Counties or Parishes ................ 49

5.2.6 Observations ........................................................................................................ 49

5.3 Industry-Specific Onshore Distributions ...................................................................... 50

5.3.1 Oil Service Contract Industries ............................................................................ 50

5.3.2 New Industries ..................................................................................................... 51

5.4 Onshore Distributions for Labor .................................................................................. 57

5.5 Modifying the Onshore Distributions for Western and Central GOM Areas .............. 67

6.0Revenue Functions .................................................................................................................. 68

7.0Literature Cited ........................................................................................................................ 73

Appendix A. Offshore Pipeline Construction Costs ............................................................... A-1

Appendix B. Structure Decommissioning Costs ..................................................................... B-1

Appendix C. FPSO and Subsea System Costs ........................................................................ C-1

Appendix D. Platform Fabrication Sites ................................................................................. D-1

Appendix E. Semisubmersible Structure Costs .......................................................................E-1
ix

LIST OF FIGURES

Figure 1. MAG-PLAN and IMPLAN interrelationship. ............................................................ 6

Figure 2. United States and the ROW ...................................................................................... 42

Figure 3. Five-State GOM Region and the Rest of the United States ...................................... 42

Figure 4. GOM counties and parishes, rest of state regions within the five-state GOM 

Region. ...................................................................................................................... 43

Figure 5. MAG-PLAN 2012 geographic regions of interest. ................................................... 44

Figure 6. Revenue function logic flow. .................................................................................... 70

Figure C-1. Cascade and Chinook Fields with subsea completions and FPSO. ........................ C-1

Figure C-2. Number of subsea completions per year. ................................................................ C-2

Figure C-3. FPSO........................................................................................................................ C-3

Figure E-1. Thunder Horse .......................................................................................................... E-6
xi

LIST OF TABLES

Table 1 Activity Function Codes and E&D Scenario Mapping ............................................. 5

Table 2 Initial Exploratory Well Costs .................................................................................. 11

Table 3 Exploratory Well Distribution by Water Depth, Well Depth, and Planning Area ... 12

Table 4 Exploratory Well Distribution between Planning Areas by Water Depth For 

Calculating Average Well Costs for Combined Western and Central GOM 

Planning Areas .......................................................................................................... 12

Table 5 Intermediate Average Exploratory Well Cost (2008$) by Water Depth and 

Planning Area ........................................................................................................... 13

Table 6 Initial Development Well Costs ............................................................................... 13

Table 7 Development Well Distribution by Water Depth, Well Depth, and Planning Area . 14

Table 8 Development Well Distribution by Water Depth and Planning Area For 

Calculating Average Well Costs for Combined Western and Central GOM 

Planning Areas .......................................................................................................... 14

Table 9 Intermediate Average Development Well Cost (2008$) by Water Depth and 

Planning Area ........................................................................................................... 15

Table 10 Lease Equipment Costs for Oil Production .............................................................. 16

Table 11 Lease Equipment Costs for Gas Production ............................................................. 16

Table 12 Estimated MAG-PLAN 2012 Exploratory Well Costs (Thousands, 2008$) ........... 17

Table 13 Estimated MAG-PLAN 2012 Nonproductive Development Well Costs 

(Thousands, 2008$) .................................................................................................. 17

Table 14 Estimated MAG-PLAN 2012 Productive Development Well Costs (Thousands, 

2008$) ....................................................................................................................... 18

Table 15 G&G Costs as a Percentage of Exploratory Drilling Costs ($millions) ................... 19

Table 16 G&G Per-Well Costs in MAG-PLAN 2012 ............................................................. 19

Table 17 Production System Costs .......................................................................................... 21

Table 18 New Onshore Gas Processing Projects 2006–2010 .................................................. 22

Table 19 Estimated Cost per Mile by Water Depth (Thousands, 2008$) ................................ 23

Table 20 Cost of Platform/Structure Decommissioning in the GOM by Water Depth 

(Thousands, 2008$) .................................................................................................. 24

Table 21 Average and High O&M Cost Per Production System by Water Depth 

(Thousands, 2008$) .................................................................................................. 25

Table 22 Estimated Onshore Gas Processing O&M Costs ...................................................... 26

Table 23 Offshore Pipeline Operating Costs (2008$) ............................................................. 27
xii

Table 24 Derivation of Labor Share for Exploratory Drilling ................................................. 29

Table 25 Derivation of Labor Share for Nonproductive Development Drilling ..................... 30

Table 26 Derivation of Labor Share for Productive Development Drilling ............................ 32

Table 27 Comparison of Labor Percentages for Drilling Wells .............................................. 33

Table 28 Cost Comparison by Water Depth ............................................................................ 35

Table 29 Cost Comparison by Number of Well Slots ............................................................. 36

Table 30 Production O&M Costs ............................................................................................ 37

Table 31 Labor Shares by Activity .......................................................................................... 39

Table 32 Texas: 63 Counties That Can Be Included in the Gulf Coast Economic Impact 

Area ........................................................................................................................... 44

Table 33 Louisiana: 40 Parishes That Can Be Included in the Gulf Coast Economic 

Impact Area .............................................................................................................. 45

Table 34 Mississippi and Alabama Counties that Can Be Included in the Gulf Coast 

Economic Impact Area ............................................................................................. 45

Table 35 Florida: 54 Counties that can be included in the Gulf Coast Economic Impact 

Area ........................................................................................................................... 45

Table 36 Overview of Top-Down Approach ........................................................................... 47

Table 37 Sample Calculation to Apportion Five-State RS among Five States ....................... 48

Table 38 Oil Service Industries and IMPLAN Sectors ............................................................ 50

Table 39 Onshore Distribution for the Platform Fabrication Activity ..................................... 52

Table 40 Subsea Equipment Manufacturers ............................................................................ 53

Table 41 Onshore Distribution for IMPLAN Sector 206—Oil And Gas Field Equipment 

And Machinery ......................................................................................................... 55

Table 42 Gulf of Mexico Insurance and Hurricane Losses ..................................................... 56

Table 43 Onshore Distribution for Labor in Offshore Oil and Gas Operations ...................... 58

Table 44 Labor Onshore Distribution: No Adjustments .......................................................... 59

Table 45 Texas Onshore Labor Distribution ........................................................................... 60

Table 46 Louisiana Onshore Labor Distribution ..................................................................... 61

Table 47 Mississippi Onshore Labor Distribution ................................................................... 62

Table 47. Mississippi Onshore Labor Distribution (cont.) ....................................................... 63

Table 48 Alabama Onshore Labor Distribution ...................................................................... 64

Table 49 Florida Onshore Labor Distribution ......................................................................... 65

Table 50 Activity Functions, Sectors, and Onshore Distributions .......................................... 66

Table 51 8(g) Funds Disbursed by Fiscal Year and State ........................................................ 71
xiii

Table 52 Average 8(g) Funds Disbursed by State ................................................................... 72

Table A-1 Offshore GOM Pipeline Projects Since 2005 ......................................................... A-2

Table A-2 Pipeline Project Water Depths ................................................................................ A-2

Table A-3 Offshore Pipeline Projects From 2005 ................................................................... A-3

Table A-5 Estimated Cost Per Mile by Water Depth (Thousands, 2008$) .............................. A-4

Table B-1 Cost of Platform/Structure Decommissioning in the GOM by Water Depth 

(Thousands, 2008$) ................................................................................................ B-2

Table B-2 Estimated Costs for Decommissioning Platforms in the Pacific OCS ................... B-3

Table C-1 Orders for Subsea Tiebacks and Completions (January 2009 through May 2010) C-5

Table C-1. Orders for Subsea Tiebacks and Completions (January 2009 through May 2010) 

(continued) .............................................................................................................. C-6

Table C-2 FPSOs ..................................................................................................................... C-8

Table D-1 Summary of Platform Fabrication Facilities ........................................................... D-6

Table D-1. Summary of Platform Fabrication Facilities (continued) ....................................... D-7

Table D-1. Summary of Platform Fabrication Facilities (continued) ....................................... D-8

Table E-1 Semisubmersible Costs ............................................................................................ E-3

Table E-2 Semisubmersible Manufacturing Locations ............................................................ E-9
1 

1.0 E XE C UTIVE S UMMAR Y

1.1 PURPOSE

The Bureau of Ocean Energy Management (BOEM) plays a key role in the U.S.’s energy 

supply by managing the mineral resources on ne arly 160 m illion acres in the Gulf of Mexico 

(GOM) Outer Continental Shelf (OCS) region. Under the National Environmental Policy Act 

(NEPA), BOEM is required to integrate environmental values into its decision-making 

processes. BOEM does this by preparing Environmental Impact Statements and other analyses 

that examine the effects of its proposed actions and reasonable alternatives to those actions. 

BOEM prepares site-specific and Gulf-wide analyses to support the five-year schedule of federal

oil and gas leasing required by the Outer Continental Shelf Lands Act (43 U.S.C. 1344). 

To support these analyses, BOEM (then known as the Minerals Management Service, or 

MMS) developed MAG-PLAN, a two-stage input-output model to estimate employment, 

personal income, and similar economic impacts from OCS activities (USDOI MMS 2005). 

MAG-PLAN’s Stage 1 starts with BOEM estimates of the level of exploration, development, 

production, and infrastructure associated with a proposed OCS lease sale or set of sales. The 

model allocates industry expenditures among IMPLAN industry sectors1 and then distributes the 

expenditure-by-sector spending to onshore areas. Stage 2 us es region-specific IMPLAN 

multipliers to calculate the jobs, earnings, and output resulting from oil and gas operations in the 

GOM OCS.

The purpose of this project is to update the data to: 

• Reflect new developments in technologies, such as floating and subsea production 

systems.

• Incorporate new costs2

• Incorporate detailed onshore distribution data for key offshore oil and gas activities. 

for major activities. (All costs are presented in thousands of 

2008). 

• Develop a methodology to estimate the onshore distribution of other industry sectors at 

different levels of granularity (i.e., national, state, or regional).

 

1 IMPLAN (IMpact Analysis for PLANning) is an input-output analysis (I-O) software package with modeling 

and data components. I-O is a means of examining relationships within an economy, both between businesses and 

between businesses and final consumers that captures all monetary market transactions for consumption in a given 

time period. The resulting mathematical formulae allow examination of the effects of a change in one or several 

economic activities on an entire economy (impact analysis). IMPLAN v.3 disaggregates the U.S. economy into 440 

industry sectors and can be used to estimate change in employment (jobs), output, and earnings from increases or 

decreases in economic activity. IMPLAN industry sectors are consistent with NAICS codes; see

http://implan.us/v3/index.php?option=com_docman&task=cat_view&gid=145&Itemid=138 for crosswalk tables. 2 MAG-PLAN models industry expenditures, which in some cases may be slightly different than industry costs. 

However, for the purpose of this report the two terms are used interchangeably.
2 

1.2 REPORT ORGANIZATION

The report is organized as follows: 

• Chapter 2.0 provides an overview of MAG-PLAN and covers basic concepts, logic flow, 

and other general information. 

• Chapter 3.0 presents the expenditure data and supporting sources. For new activity 

functions developed for MAG-PLAN 2012 (i.e., geological and geophysical prospecting; 

Floating, Production, Storage, and Offloading [FPSOs]; and subsea systems), Chapter 3 

also discusses the allocation of those costs among the 440 IMPLAN sectors. 

• Chapter 4.0 discusses the methodology used to estimate the percentage of total 

expenditures formed by payments to labor. 

• Chapter 5.0 focuses on the “onshore distribution” methodology, which traces how labor 

and non-labor expenditures flow from the offshore regions to onshore regions in the 

GOM. 

• Chapter 6.0 describes revenue functions and how they are incorporated within MAGPLAN.

• Chapter 7.0 discusses the strengths and weaknesses of MAG-PLAN 2012. 

This report focuses on methodology and data; a separate user’s manual focuses on t he 

software requirements, model structure, and instructions for running the model. 
3 

2.0 INTR ODUCTION

2.1 HISTORY

The Outer Continental Shelf Lands Act (OCSLA), as amended, established a policy for the 

management of oil and natural gas in the OCS and for protection of the marine and coastal 

environments. The OCSLA requires preparing and maintaining a current five-year schedule of 

proposed lease auctions. NEPA requires preparation of an Environmental Impact Statement

(EIS) before any major federal action. BOEM is the administrative agency responsible for 

leasing submerged federal lands and prepares an EIS before each Five-Year Program and 

subsequent lease sales. 

BOEM evaluates the environmental impacts, including onshore socioeconomic impacts, of 

oil and gas activities in the OCS. Shortly after the passage of OCSLA, as amended, in 1978, 

BOEM (then MMS) began its efforts to model the implications of offshore development on 

onshore communities. Luton and Cluck (2000) tracks 15 years of data, methodology 

development, and analyses performed by the Environmental Studies Program from the first 

large-scale studies published in the mid-1980s. In the late 1990s, MMS’s Developmental 

Benefits Model Assessment Team developed a consistent approach to regional economic 

modeling across OCS regions, and the first resulting OCS Economic Impact Model for the GOM 

was created soon thereafter. This model employed a two-stage, input-output framework to 

estimate employment, personal income, and similar economic impacts from OCS activities.

By 2005, MMS had developed the second generation of OCS Economic Impact Models, 

collectively named MAG-PLAN, which extended the consistent approach and incorporated both 

the GOM and Alaska OCS models into a s ingle software framework (USDOI MMS 2005). 

MAG-PLAN’s Stage 1 starts with BOEM estimates of the level of exploration, development, 

production, and infrastructure associated with a proposed OCS lease sale or set of sales (called 

an exploration and development, or E&D, scenario). The model allocates industry expenditures 

among IMPLAN industry sectors and then distributes the expenditure-by-sector spending to 

onshore areas. Stage 2 uses input-output multipliers from IMPLAN,3 a commercial regional 

economic modeling program, to estimate employment, personal income, and other economic 

effects associated with different E&D scenarios by onshore area and type or impact.

This report is a continuation of BOEM’s efforts to update, expand, and refine its 

socioeconomic impact analysis capabilities. Deepwater projects now generate the majority of oil 

production and about one-third of the gas production in the GOM OCS (USDOI MMS 2009). 

 

3 IMPLAN (IMpact Analysis for PLANning) is an input-output analysis (I-O) software package with modeling 

and data components. I-O is a means of examining relationships within an economy, both between businesses and 

between businesses and final consumers that captures all monetary market transactions for consumption in a given 

time period. The resulting mathematical formulae allow examination of the effects of a change in one or several 

economic activities on an entire economy (impact analysis). IMPLAN v.3 disaggregates the U.S. economy into 440 

industry sectors and can be used to estimate change in employment (jobs), output, and earnings from increases or 

decreases in economic activity. IMPLAN industry sectors are consistent with NAICS codes; see

http://implan.us/v3/index.php?option=com_docman&task=cat_view&gid=145&Itemid=138 for crosswalk tables.
4 

The revised version of MAG-PLAN now has activity functions for FPSO vessels, subsea

completions, and updated costs for other activity functions, as well as software upgrades.

2.2 BASIC CONCEPTS

2.2.1 Direct, Indirect, and Induced Effects

As mentioned previously, a goal of MAG-PLAN is to estimate the number of jobs, earnings, 

and economic output associated with oil and gas activities in the GOM OCS. MAG-PLAN Stage 

1 tracks the “direct effects” (e.g., the number of jobs associated with drilling a well). 

Stage II estimates the associated “indirect” and “induced” economic effects. Indirect effects 

are associated with the economic activities involved with backfilling a supply chain. For 

example, the steel pipe and cement consumed when a well is drilled create a demand to replenish 

these commodities, which, in turn, supports jobs in the steel and cement industries. “Induced 

effects” occur through household spending of the wages earned from drilling the well. The 

different types of effects structure MAG-PLAN’s logic and calculations.

2.2.2 Activity Types/Activity Functions

The starting point for a BOEM socioeconomic analysis is an exploration and development 

(E&D) scenario developed by the BOEM Resource Evaluation Office, in which the Bureau 

estimates the oil-and-gas-related activities that could reasonably take place as a result of a 

proposed project, lease sale, or set of lease sales. A scenario describes activities that occur each 

year. These E&D activities, called activity types, are modeled in MAG-PLAN as activity 

functions. Table 1 cross-references the activity types in the E&D scenarios with the activity 

functions in MAG-PLAN.4

As can be seen in Table 1, the activity types in an E&D scenario do not necessarily have a 

1:1 correspondence to MAG-PLAN activity functions. For example, collecting seismic data to 

identify where to drill (i.e., geological and geophysical prospecting) might take place before a 

lease sale, before drilling an exploratory well, or after drilling an exploratory well if data 

collected while drilling the well (e.g., velocity) are used to process the G&G data properly 

(DeCort, personal communication, 2010).

The “cradle-to-grave” (from geological and geophysical prospecting 

to decommissioning) approach is characteristic of BOEM impact analyses. 

5 Likewise, the type of production system added will 

depend, in part, on the water depth in which the system is located. 

 

4 Readers familiar with the previous version of MAG-PLAN will note several changes in Table 1. The 

Exploratory Well Drilling activity type now maps to two activity functions: geological and geophysical prospecting 

and exploratory well drilling. Subsea Added and FPSO Added are new Activity Types to reflect the growth in the 

use of floating structures (e.g., spar, tension leg platform (TLP), mini-TLPs, semisubmersible systems) in addition to 

the more traditional caisson and fixed platform. Workover costs are now included within the annual O&M cost. 

5 Section 3.2 presents ERG’s rationale for including G&G as part of the activity function for drilling 

exploratory wells in MAG-PLAN.
5 

Table 1 

Activity Function Codes and E&D Scenario Mapping

Activity Types in E&D Scenario Activity Function in MAG-PLAN

Exploratory Well Drilled Geological & Geophysical Prospecting

Exploratory Well Drilling

Non-Productive Well Drilled Non-Productive Well Drilling

Productive Well Drilled Productive Well Drilling

Platform Added Platform Fabrication and Installation

Operating and Maintenance Costs

Subsea Added Subsea completion(s)

Operating and Maintenance Costs

FPSO Added Floating Production, Storage, and Offloading 

Operating and Maintenance Costs

Gas Processing Facility– Offshore Gas Processing Facility-Offshore

Gas Processing Facility– Onshore Gas Processing Facility-Onshore

Gas Production Gas Processing Operating and Maintenance Costs

Pipeline Miles Added Pipeline Construction

Platform Removed – No Explosives Platform Removed-No Explosives

Platform Removed – with Explosives Platform Removed-With Explosives

Oil Spill – Reaching Shore6 Oil Spill-reaching shore

Oil Spill – Not Reaching Shore Oil Spill-not reaching shore

Source: Updated from USDOI MMS (2005) 

2.3 ACTIVITY FUNCTIONS IN MAG-PLAN

To run MAG-PLAN, the user must first use IMPLAN. The programs, then, are intertwined. 

Figure 1 illustrates this interrelationship. IMPLAN calculations and outputs are shown in the 

thick lines that surround and enter the center box that holds the MAG-PLAN calculations. 

2.3.1 Prerequisite IMPLAN Analyses

The overall steps for running IMPLAN analyses prior to conducting a MAG-PLAN analysis 

are:

• Identify the geographic regions of interest 

• Create an IMPLAN model for each region

• Create an IMPLAN analysis with a $1 million change in labor income 

• Create a matrix of induced multipliers by region for labor expenditures 

• Import into MAG-PLAN for use in Stage 2 calculations 

 

6 Rather than updating this function, which is not currently used, BOEM is exploring the possibility of 

estimating a broader range of employment effects, including job gains and lossesskm9me59 that may result from oil 

spills.
6 

Figure 1. MAG-PLAN and IMPLAN interrelationship. 
7 

The IMPLAN model generates the direct, indirect, and induced multipliers for the non-labor 

expenditures by industry sector. Running the $1 million change in labor income to calculate the 

induced effect multipliers replaces the approach in MAG-PLAN 2005, which calculated 

disposable income, distributed the income among several income categories, and distributed the 

spending through the personal consumption expenditure matrix7

2.3.2 Setting up MAG-PLAN

to estimate spending by 

industry sector within Stage 1 (USDOI MMS 2005). 

Before analyzing an E&D scenario, the user must first define the MAG-PLAN Economic 

Regions to correspond to those in the IMPLAN Models. The regions must also have the same 

names as well as the same set of counties or parishes within them. The user will import an E&D

scenario, select the offshore modeling area (e.g., Western GOM, Central GOM), designate the 

dollar base year for the analysis and select the start and end years, define or select the onshore 

areas to include in the analysis, and import the associated sets of IMPLAN multipliers for laborincome and non-labor expenditures for these onshore areas.8

2.3.3 Sample MAG-PLAN Calculation Flow

The logic flow within the white box in Figure 1 illustrates the calculations that take place 

when the model is executed for a given E&D scenario. BOEM develops an E&D scenario with 

counts of each activity type that take place in a given year, for example, 2 platforms are added in 

Year 5. MAG-PLAN maps activity types to activity functions (see Table 1, a bove). The 

expenditures associated with each activity function form the shock to the model. The purpose of 

Stage 1 is to process the initial shock (e.g., drill a development well, construct and install a 

production platform, etc.) into non-labor and labor expenditures suitable for using with IMPLAN 

multipliers for indirect and induced effects. Chapter 3.0 provides details on the estimated 

expenditure(s) associated with each activity function. Because all MAG-PLAN 2012 data are in 

terms of 2008$, the first step is to inflate the values to base year dollars for the analysis. The 

shock is then divided into non-labor and labor components. 

2.3.3.1 Non-labor Expenditures

MAG-PLAN 2012 is configured with a “Technology Change Series” input class for nonlabor expenditures to reflect a “learning curve” with new technology. (That is, the first of any 

new technology might be very expensive to build while, further up the learning curve, 

subsequent examples are less expensive.) Currently, the default value is for the Technology 

Factor is 1.0 (meaning there is no adjustment for changes in technology) but this can be changed 

by the user.

Next, non-labor expenditures are allocated among the 440 IMPLAN industry sectors based 

on the methodology in USDOI MMS (2005) pages 21 through 29. The Activity by Sector matrix 

represents the outcome of examining the top five sectors in the production function for an 

activity and re-distributing the original share of a sector among all the sectors that “feed” into its 

production function. The production function used by ICF to estimate the first-round effects is 

based on an IMPLAN model of 31 parishes in Southern Louisiana (USDOI MMS 2005). It is 

 

7 Spending patterns differ by income level.

8 The user must also select or confirm the remaining input class selections. The default input class selections 

will normally be acceptable for most analyses.
8 

this process that provides the basis for the statement in USDOI MMS (2005) that, in MAGPLAN, direct effects also incorporate the first round spending effects. Sector allocations for 

geological and geophysical prospecting, FPSOs, and subsea systems are discussed in Chapter 

3.0. 

In MAG-PLAN 2012, non-labor expenditures by sector are distributed to onshore areas by 

one of two approaches. The first approach is an industry-specific onshore distribution built from 

the bottom up b y examining company and facility data. ERG 2011 examined about 1,140 

locations for 17 oil service industries.

9

The end result is a matrix of expenditures by industry sector by onshore area. The sum of all 

the Stage 1 non-labor entries should equal the inflation-adjusted non-labor expenditure for the 

activity. 

For the MAG-PLAN 2012 update, these 17 distributions 

were combined into onshore distributions for 8 IMPLAN sectors. ERG also used the same 

approach to develop onshore distributions for the platform fabrication industry (IMPLAN sector 

209 for shipbuilding and repairing), subsea completion component of the oil and gas field 

equipment and machinery (IMPLAN sector 206), and insurance carriers (IMPLAN industry 

357). The second approach used IMPLAN’s “regional purchase coefficients” (RPCs) as proxies 

to estimate the proportion of demand supplied from sources within the region (“regional shares” 

or RSs). This approach started at the largest scale (e.g., U.S. versus Rest of World), and worked 

through smaller and smaller scales until onshore distributions could be developed by industry for 

the economic impact areas within each of the five Gulf States (Texas, Louisiana, Mississippi, 

Alabama, and Florida) and the rest of each state. For the purpose of this report, the term “GOM 

economic area” refers to the five Gulf States while the term “GOM economic impact areas” 

refers to subsets of counties and parishes BOEM considered most likely to be impacted by oil 

and gas operations in the OCS. Chapter 5.0 presents the methodology for developing the onshore 

distributions. While these approaches provide some improvements to the 2005 distributions, they 

represent intermediate steps that will likely be refined in the future. 

2.3.3.2 Labor Income Expenditures

As with the non-labor expenditures, MAG-PLAN is configured with a “Productivity Change 

Series” input class for labor income expenditures to address a s ituation where technological 

development results in an increase in labor productivity (see Figure 1). Labor income 

expenditures are distributed to onshore areas by activity function. 

MAG-PLAN 2005 had a single onshore distribution based on the Labor Needs Survey (ICF 

2008) for all labor expenditures. MAG-PLAN 2012 uses the same onshore distributions for labor 

income expenditures as for non-labor expenditures, except for the following activity functions: 

• Exploratory drilling

• Development drilling

• Development drilling and completion

• Production operations and maintenance, including workovers. 

 

9 Geological and geophysical prospecting, contract drilling, drilling fluid supplies, drilling tools and supplies, 

mud logging, measurement while drilling (MWD), cementing, formation evaluation, completion, fishing, wellhead 

equipment suppliers, accommodations, air transport, water transport, catering, workovers, and diving support.
9 

The onshore distribution based on the Labor Needs Survey is applied to these four activity 

functions, see Section 5.4 for details.

2.3.4 Stage 2 Calculations

Stage 2 is where the multiplication of 440 industry sectors by 8 IMPLAN multipliers by n

regions takes place.10

2.4 REVENUE FUNCTIONS IN MAG-PLAN

The results can be exported as .csv files, summarized into tables, or 

otherwise processed as needed for BOEM reports. The non-labor expenditures—allocated into 

industry sectors and distributed to onshore areas—are multiplied by the direct, indirect, and 

induced effect regional multipliers generated by the regional IMPLAN models. The labor income 

expenditures—distributed to onshore areas by activity function—are multiplied by the induced 

effect regional multipliers estimated by the $1 million change in labor income generated in the 

regional IMPLAN models. The multiplier represents the number of jobs created in each region 

by a $1 m illion change in labor income, and is a weighted average of the labor income 

multipliers for each of the 440 industry sectors for each region. 

BOEM collects funds from oil and gas operations in the OCS through: 

• Bonus bids 

• Rental payments

• Royalties on oil and gas production 

A bonus is the cash consideration paid to the United States by the successful bidder for a 

mineral lease. Rental payments are paid (usually annually) on a lease from the time of the sale 

until oil and gas production begins on t he lease or the lease expires, whichever comes first. 

Royalties are a percentage of the value of production from the lease. 

OCSLA, as amended, requires that the federal government set aside 27 percent of the bonus, 

rental, and royalty income received from leases within 3 miles of the edge of state waters. The 3-

mile band of federal waters is known as the “8(g) zone” after the section of the legislation that 

created the requirement. The BOEM Economics Division staff calculates the annual “8(g)” and 

“non-8(g)” revenues for an E&D scenario from which anticipated bonuses, rentals, and royalties

are calculated; these form six separate columns in the E&D scenario spreadsheet. The onshore 

distribution and sector allocation for the revenue functions are discussed in Chapter 6.0. 

 

10 MAG-PLAN 2012 uses the aggregated multipliers for output, employment, total value added, labor income, 

proprietor income, employee compensation, indirect business tax, and other property type income. The previous 

version used the disaggregated multiplier matrices. BOEM determined that any change to a region’s inter-industry 

relationships would be best made within IMPLAN rather than MAG-PLAN 2012. In addition, the change from an 

industry by industry by multiplier type matrix (i.e., 440 by 440 by 8) to an industry by multiplier type matrix (i.e., 

440 by 8) leads to increased stability and faster processing time.
10 

3.0 INDUS TR Y E XPE NDITUR E S 

The base year for the MAG-PLAN update is 2008, based on the most recent IMPLAN data 

available at the time this effort was undertaken. All expenditures11 are inflated/deflated to 2008$ 

using the Consumer Price Index (CPI-U) (USDOL BLS 2010) and are presented in units of 

thousands of dollars. MAG-PLAN output is inflated to the base year set by the user. All MAGPLAN estimates are in base-year constant dollars. 

ERG updated expenditures for:

• Wells (Section 3.1) 

• Geological and geophysical prospecting (Section 3.2) 

• Platform fabrication and installation, subsea systems, and floating systems (Section 3.3) 

• Onshore gas processing facilities (Section 3.4) 

• Offshore pipeline construction costs (Section 3.5) 

• Platform decommissioning (Section 3.6) 

• Production operations and maintenance (Section 3.7) 

• Onshore gas processing operations and maintenance (Section 3.8) 

• Pipeline operations and maintenance (Section 3.9) 

ERG also developed the sector allocation for new activity functions (Section 3.10). 

Note that operating and maintenance expenditures (Sections 3.8 and 3.9) are annual activities 

that occur each year for the lifetime of the capital asset with which they are associated. 

ERG did not update the oil spill cleanup expenditures from those published in USDOI MMS

(2005). Rather than updating this function, which is not currently used, BOEM is exploring the 

possibility of estimating a broader range of employment effects, including job gains and losses

that may result from oil spills.

For some activities, the discussion of the data sources and estimation methods is detailed and 

complex.12

3.1. DRILLING AND ASSOCIATED GEOLOGICAL AND GEOPHYSICAL 

PROSPECTING

These discussions are included in appendices, while the findings are summarized in

Chapter 3. 

BOEM took the opportunity to coordinate the expenditure estimates for wells and platforms 

used in the models for resource evaluation and socioeconomic impact models. Section 3.1.1 

discusses the initial expenditures for exploration wells, and Section 3.1.2 discusses the initial 

expenditures for nonproductive development wells. Section 3.1.3 d escribes the potential 

increases to drilling expenditures due to the interim final rule for increased safety measures 

published by BOEM (then known as BOEMRE) on October 14, 2010 (USDOI BOEMRE

 

11 MAG-PLAN models industry expenditures, which in some cases may be slightly different than industry costs. 

However, for the purpose of this report the two terms are used interchangeably. 12 Because we rely on published data for much of the population of MAG-PLAN variables, there is some 

inevitable mixture of onshore and offshore oil and gas activities in those data. (The NAICS does not distinguish 

between onshore and offshore regions.) Throughout this report, ERG has described the steps taken to identify 

offshore operations more closely. While the current model calculates reasonable projections for the socioeconomic 

impacts of oil and gas activities in the offshore region, the further specification of offshore operations would refine 

these projections.
11 

2010a). Finally, the expenditures for completing and equipping productive development wells 

are discussed in Section 3.1.4. Section 3.1.5 i s a summary of the expenditures included in 

MAGPLAN 2012. 

3.1.1 Exploration Wells

The GOMR Office of Resource Evaluation (ORE) estimated well costs using three sources: 

(a) the offshore oil and gas supply module equations developed by the U.S. Department of 

Energy, Energy Information Administration as part of its National Energy Modeling System 

(NEMS) USDOI EIA (2010a), (b) FieldPlan Offshore Facility Evaluation software, and (c) 

internal cost databases maintained by ORE. Estimated well costs were modeled assuming an oil 

price of approximately $100/BO for the high case and $80/BO for the low case. The cost data 

were analyzed to create the hybrid; estimated exploratory well and productive development well 

range (high, mid, low) of well costs. Well depth is given in units of feet while water depth is 

given in units of meters (as in MAG-PLAN). ERG deflated the high cost estimates to 2008$ (see 

Table 2). The three-phase methodology was used in order to incorporate all available data and 

develop ranges of well costs that afford flexibility for MAG-PLAN input requirements. 

Table 2

Initial Exploratory Well Costs

Initial Exploratory Well Cost (2008$)

Well Depth (ft)

Water Depth (m) 0 to 15,000 15,000 to 18,000 18,000+

0–60 $8,137,500 $18,066,667 $32,037,000

60–200 $18,709,500 $35,825,000 $48,885,667

200–400 $21,997,500 $42,478,250 $58,678,667

400–800 $26,336,000 $50,918,000 $70,360,000

800–1,600 $32,917,000 $64,682,500 $97,787,667

1,600–2,400 $40,381,500 $88,609,000 $143,590,333

2,400 + $45,134,667 $103,967,000 $177,984,000

Source: USDOI BOEM (2011b), high cost estimates, deflated to 2008$. 

ERG calculated “average” well costs by water depth for the Western and Central GOM 

planning areas based on the historical distribution of well depths by water depths seen in each 

planning area (see Table 3).

13 ERG then used the well distribution by water depth by OCS 

planning area (see Table 4) to develop an “average” initial well cost by water depth for the 

combined Western and Central GOM planning areas (see Table 5). 

 

13 The historical distribution of well depths may underestimate the depths of the projected wells in the E&D 

forecast because ORE’s analysis of historical well depths in the GOM suggests that there is a positive correlation 

between time (years) and annual average well depth.
12 

Table 3

Exploratory Well Distribution by Water Depth, Well Depth, and Planning Area

 Well Depth 

Water Depth (m) 0 to 15,000 15,000 to 18,000 18,000+ Sum

Western Gulf of Mexico

0–60 78% 20% 2% 100%

60–200 92% 1% 7% 100%

200–400 79% 7% 14% 100%

400–800 79% 7% 14% 100%

800–1,600 62% 15% 23% 100%

1,600–2,400 48% 1% 51% 100%

2,400 + 92% 4% 4% 100%

Central Gulf of Mexico

0–60 71% 18% 11% 100%

60–200 90% 7% 3% 100%

200–400 93% 3% 4% 100%

400–800 93% 3% 4% 100%

800–1,600 60% 10% 30% 100%

1,600–2,400 45% 16% 39% 100%

2,400 + 45% 15% 40% 100%

Source: USDOI BOEM (2011c).

Table 4

Exploratory Well Distribution between Planning Areas by Water Depth For Calculating Average Well 

Costs for Combined Western and Central GOM Planning Areas

Water Depth (m)

GOM Planning Area

Western Central

0–60 18.7% 81.3%

60–200 24.7% 75.3%

200–400 28.4% 71.6%

400–800 28.4% 71.6%

800–1,600 30.7% 69.3%

1,600–2,400 8.8% 91.2%

2,400 + 24.7% 75.3%

Source: Calculated from well count data by planning area in USDOI 

BOEM (2011c).
13 

Table 5

Intermediate Average Exploratory Well Cost (2008$) by Water Depth and Planning Area

Planning Area

Water Depth (m) Western Central

Western and 

Central

0–60 $10,601,323 $12,553,695 $12,188,601

60–200 $20,992,987 $20,812,870 $20,857,359

200–400 $28,566,516 $24,079,169 $25,353,576

400–800 $34,220,100 $28,834,420 $30,363,953

800–1,600 $52,602,078 $55,554,750 $54,648,280

1,600–2,400 $93,500,280 $88,349,345 $88,802,627

2,400 + $52,801,933 $107,099,250 $93,687,813

Source: ERG estimates derived from data in Tables 2 through 4. 

3.1.2 Nonproduction Development Wells

ERG used the same methodology as with exploration wells (see Section 3.1.1 a bove) to 

calculate average well costs for nonproduction development wells. The term refers to wells that 

differ from exploratory well costs because they have been drilled from a platform rather than a 

mobile offshore drilling unit or MODU. The development well costs provided by ORE do not 

contain completion costs for final activities after the casing has been run (such as swabbing) to 

put the well into production. Nor do the ORE cost estimates include lease equipment costs 

associated with production. The nonproduction well costs are representative of wells drilled to 

delineate the reservoir or for water injection. Table 6 is the initial set of development well costs 

provided by ORE and deflated to 2008$. Table 7 lists the distributions with which to calculate an 

average well cost by water depth and planning area, while Table 8 lists the distributions used in 

the calculation of a combined average Western and Central GOM planning area development 

well. Table 9 is the intermediate cost for a development well that is not put into production. 

Table 6

Initial Development Well Costs

Initial Development Well Cost (2008$)

Well Depth (ft)

Water Depth (m) 0 to 15,000 15,000 to 18,000 18,000+

0–60 $6,095,500 $14,424,667 $27,985,500

60–200 $8,228,000 $18,347,000 $36,067,000

200–400 $9,629,250 $20,264,500 $38,673,667

400–800 $12,629,667 $25,803,000 $42,686,000

800–1,600 $17,738,500 $33,499,333 $49,615,000

1,600–2,400 $19,529,667 $39,007,333 $55,076,250

2,400 + $22,224,167 $45,034,833 $61,404,500

Source: USDOI BOEM (2011b), high cost estimates, deflated to 2008$. 
14 

Table 7

Development Well Distribution by Water Depth, Well Depth, and Planning Area

 Well Depth 

Water Depth (m) 0 to 15,000 15,000 to 18,000 18,000+ Sum

Western Gulf of Mexico

0–60 88% 10% 2% 100%

60–200 97% 1% 2% 100%

200–400 76% 4% 20% 100%

400–800 76% 4% 20% 100%

800–1,600 45% 40% 15% 100%

1,600–2,400 50% 5% 45% 100%

2,400 + 98% 1% 1% 100%

Central Gulf of Mexico

0–60 88% 10% 2% 100%

60–200 93% 5% 2% 100%

200–400 95% 2% 3% 100%

400–800 95% 2% 3% 100%

800–1,600 60% 20% 20% 100%

1,600–2,400 55% 15% 30% 100%

2,400 + 60% 5% 35% 100%

Source: USDOI BOEM (2011c).

Table 8

 

Development Well Distribution by Water Depth and Planning Area For Calculating 

Average Well Costs for Combined Western and Central GOM Planning Areas 

Water Depth (m)

GOM Planning Area

Western Central

0–60 9.7% 90.3%

60–200 15.5% 84.5%

200–400 13.4% 86.6%

400–800 13.4% 86.6%

800–1,600 18.2% 81.8%

1,600–2,400 13.6% 86.4%

2,400 + 52.5% 47.5%

Source: Calculated from well count data by planning area in USDOI BOEM (2011c).estimates. 
15 

Table 9

Intermediate Average Development Well Cost (2008$) by Water Depth and Planning Area

 Planning Area

Water Depth (m) Western Central

Western and 

Central

0–60 $7,366,217 $7,366,217 $7,366,217

60–200 $8,885,970 $9,290,730 $9,227,992

200–400 $15,863,543 $10,713,288 $11,403,422

400–800 $19,167,867 $13,794,823 $14,514,811

800–1,600 $28,824,308 $27,265,967 $27,549,585

1,600–2,400 $36,499,513 $33,115,292 $33,575,546

2,400 + $22,844,077 $37,077,817 $29,605,103

Source: ERG estimates derived from data in Tables 6 through 8. 

3.1.3 Increased Costs Due to New Regulatory Requirements

BOEM (then known as BOEMRE) published an interim final rule on October 14, 2010 , 

regarding increased safety measures for offshore oil and gas drilling operations (USDOI 

BOEMRE 2010a). The new requirements mean additional rig time and tests to be made during 

the drilling operations. Based on t he benefit-cost analysis for the interim rule, the percentage 

increase to the well costs would be:

• 1.58 percent for all exploratory wells and for development wells drilled from MODUs

• 0.6 percent for development wells drilled from fixed platforms

(USDOI BOEMRE 2010b). 

Because ERG assumes that production structures in water depths up t o 200 m are fixed 

platforms, development wells drilled in water depths up to 200 m are increased by 0.6 percent. 

All other wells (that is, all exploratory wells plus development wells drilled in water depths 

greater than 200 m) are increased by 1.58 percent. 

3.1.4 Productive Development Wells

To estimate the total expenditures for putting a development well into production, ERG 

added the expenditures to complete and equip the well to the expenditures presented in Sections 

3.1.2 and 3.1.3. ERG estimated completion costs and lease equipment costs separately. 

Completion costs might vary by well depth because of the differing amounts of cement to seal 

the casing. The U.S. Department of Energy (USDOE) National Energy Technology Laboratory 

(NETL) developed a benchmarking report of deep well costs (USDOE NETL 2005) that contains 

very detailed costs as they might appear on an authorization for expenditure form. Well 

completion services are a line item and, for an offshore development well, they form 

approximately 3.1 percent of the total well costs.

The USDOE Energy Information Administration (EIA) publishes an annual report on oil and 

gas lease equipment and operating costs (USDOE EIA 2010a). The report presents data for 

onshore lease equipment costs but not for offshore operations. However, with the exception of 
16 

transportation costs, the equipment costs for processing oil and gas will depend more on the 

volume of oil or gas that needs to be processed rather than whether the equipment is located 

above land or water. USDOE EIA (2010a) presents lease costs for oil production on the basis of 

a 10-well project. Table 10 s ummarizes the average lease equipment costs for oil production, 

while Table 11 summarizes the lease equipment costs for gas production. The equipment for oil 

production ranges from $142,000 per well to $381,000 per well. In contrast, equipment for gas 

production ranges from $36,000 for a small, shallow well to $176,000 for a deep well producing 

10 MMcf/day. 

Table 10

Lease Equipment Costs for Oil Production

Cost (2008$)

Well Depth 

(ft) Project Per-well

2,000 $1,417,700 $141,770

4,000 $1,917,100 $191,710

8,000 $2,808,800 $280,880

12,000 $3,808,600 $380,860

Average $2,488,100 $248,810

Source: USDOE EIA (2010a) 

Table 11

Lease Equipment Costs for Gas Production

Costs in 2008$ by Per-Well Gas Production Rate

Well Depth 

(ft)

50

Mcf/day 250 Mcf/day 500 Mcf/day

1

MMcf/day

5 

MMcf/day

10 

MMcf/day Average

2,000 $35,800 $36,200 $36,000

4,000 $35,800 $55,400 $64,100 $51,800

8,000 $45,800 $86,800 $84,600 $118,300 $83,900

12,000 $109,900 $105,900 $118,000 $140,300 $118,500

16,000 $113,500 $118,300 $140,200 $175,800 $137,000

Average $36,600 $66,700 $93,100 $118,100 $140,300 $175,800

Source: USDOE EIA (2010a) 

Because we do not know, a priori, whether a well will produce oil or gas, for the purpose of 

estimating costs, ERG uses the average oil production equipment cost of $248,800. That is, the 

expenditures on completion and equipment for a well are 3.1 percent of the well cost plus 

$248,800. 
17 

3.1.5 Final Well Costs in MAG-PLAN 2012

Tables 12 through 14 are the well costs in MAG-PLAN 2012; they are in thousands of 

2008$. Exploratory wells have the 1.58 percent increase due to new regulatory costs. 

Development well costs are increased by 0.6 percent if drilled in water depths up to 200 m and 

by 1.58 percent if drilled in deeper waters to reflect increased regulatory costs. Productive 

development wells have the added completion and equipment costs described in Section 3.1.4. 

 

Table 12

Estimated MAG-PLAN 2012 Exploratory Well Costs (Thousands, 2008$)

Exploratory Well Cost (Thousands, 2008$)

 Well Depth (ft) Average

Water Depth 

(m) 0 to 15,000 15,000 to 18,000 18,000+ Western Central

Western & 

Central

0–60 $8,266 $18,352 $32,543 $10,769 $12,752 $12,381

60–200 $19,005 $36,391 $49,658 $20,993 $21,079 $20,857

200–400 $22,345 $43,149 $59,606 $28,567 $24,402 $25,354

400–800 $26,752 $51,723 $71,472 $34,220 $29,221 $30,364

800–1,600 $33,437 $65,704 $99,333 $52,602 $55,867 $54,648

1,600–2,400 $41,020 $90,009 $145,859 $93,500 $88,636 $88,803

2,400 + $45,848 $105,610 $180,796 $52,802 $107,420 $93,688

Source: ERG estimates based on data in Table 5 and information in Section 3.1.3.

Table 13

Estimated MAG-PLAN 2012 Nonproductive Development Well Costs (Thousands, 2008$)

Nonproductive Development Well Cost (Thousands, 2008$)

Well Depth (ft) Average

Water Depth 

(m) 0 to 15,000 15,000 to 18,000 18,000+ Western Central

Western & 

Central

0–60 $6,132 $14,511 $28,153 $7,410 $7,410 $7,410

60–200 $8,277 $18,457 $36,283 $8,939 $9,346 $9,283

200–400 $9,781 $20,585 $39,285 $16,114 $10,883 $11,584

400–800 $12,829 $26,211 $43,360 $19,471 $14,013 $14,744

800–1,600 $18,019 $34,029 $50,399 $29,280 $27,697 $27,985

1,600–2,400 $19,838 $39,624 $55,946 $37,076 $33,639 $34,106

2,400 + $22,575 $45,746 $62,375 $23,205 $37,664 $30,073

Source: ERG estimates based on data in Table 9 and information in Section 3.1.3.
18 

Table 14

Estimated MAG-PLAN 2012 Productive Development Well Costs (Thousands, 2008$)

 Productive Development Well Cost (Thousands, 2008$)

Well Depth (ft) Average

Water Depth 

(m) 0 to 15,000 15,000 to 18,000 18,000+ Western Central

Western & 

Central

0–60 $6,571 $15,210 $29,275 $7,889 $7,889 $7,889

60–200 $8,783 $19,278 $37,657 $9,465 $9,885 $9,820

200–400 $10,333 $21,472 $40,751 $16,863 $11,469 $12,191

400–800 $13,476 $27,272 $44,953 $20,323 $14,696 $15,450

800–1600 $18,826 $35,332 $52,210 $30,436 $28,804 $29,101

1,600–2,400 $20,702 $41,101 $57,930 $38,474 $34,930 $35,412

2,400 + $23,524 $47,413 $64,557 $24,173 $39,080 $31,254

Source: ERG estimates based on data in Tables 9 and 10 and information in Section 3.1.3.

3.2 GEOLOGICAL & GEOPHYSICAL (G&G) PROSPECTING

G&G activities can occur at many phases in an offshore oil and gas operation—before a lease 

bid, before drilling an exploratory well, or after drilling an exploratory well if data collected 

while drilling the well (e.g., velocity) are used to process the G&G data properly (DeCort, 2010). 

For the purpose of including these costs in MAG-PLAN, ERG needs to be able to associate 

G&G expenses with the activities in E&D scenarios. Based on how the publicly available data 

are presented, ERG makes two modeling assumptions: 

• All G&G costs are associated with exploratory wells 

• Costs are incurred in the year prior to drilling the exploratory well 

This approach has the effect of associating higher G&G costs with more expensive wells. 

EIA collects financial data on major energy producers (USDOE EIA 2008). In completing 

the Form EIA-28 (financial reporting), companies with oil and gas activities file a S chedule 

5211, which provides expense information by geographic region (USDOE EIA 2009a). In 

USDOE EIA (2008) Table T7, exploration costs are subdivided into: 

• Acquisition of unproved acreage 

• Geological and geophysical

• Drilling and equipping 

• Other

Development costs are subdivided into: 

 

• Acquisition of proved acreage 

• Lease equipment

• Drilling and equipping 

• Other
19 

G&G expenses are reported only under exploration activities. This supports ERG’s decision 

to assign G&G costs only to exploratory wells. 

Table 15 is derived from the Schedule 5211 submissions (USDOE EIA 2009a). “Other” costs 

include direct overhead costs associated with exploration, carrying costs of undeveloped 

properties (lease rents); test hole contributions; and land development, leasing, and scouting 

(USDOE EIA 2009b). 

From Table 15, we see that G&G costs range from a low of 15 percent of exploration drilling 

costs in 2006 to a high of 31 percent in 2003. The data for 2003 are likely to include the costs for 

Encana’s well in the Beaufort Sea, but this is the only Alaskan well we could identify between

2000 and 2007 (USDOI MMS 2006). However, because the G&G-to-drilling cost percentage for 

2003 lies within the range shown for the other years, we do not expect the inclusion of an 

Alaskan well to substantially change the average value of 21 percent. Thus, ERG estimated G&G 

costs as 21 percent of the exploratory well drilling cost (see Table 16). 

Table 15

G&G Costs as a Percentage of Exploratory Drilling Costs ($millions)

Year

Parameter 2000 2001 2002 2003 2004 2005 2006 2007 Average

G&G $573 $466 $466 $394 $607 $616 $590 $664

Drilling and 

Equipment $2,004 $2,169 $1,781 $1,804 $1,320 $2,163 $3,402 $2,458

Other $340 $340 $421 $398 $661 $726 $654 $831

G&G as a 

Percentage of 

Drilling Costs 24% 19% 21% 18% 31% 21% 15% 20% 21%

Source: USDOE EIA 2009a

Table 16

G&G Per-Well Costs in MAG-PLAN 2012

G&G Costs (Thousands, 2008$)

 Well Depth (ft) Average

Water Depth 

(m) 0 to 15,000 15,000 to 18,000 18,000+ Western Central

Western & 

Central

0–60 $1,736 $3,854 $6,834 $2,261 $2,678 $2,600

60–200 $3,991 $7,642 $10,428 $4,409 $4,427 $4,380

200–400 $4,692 $9,061 $12,517 $5,999 $5,125 $5,324

400–800 $5,618 $10,862 $15,009 $7,186 $6,136 $6,376

800–1,600 $7,022 $13,798 $20,860 $11,046 $11,732 $11,476

1,600–2,400 $8,614 $18,902 $30,630 $19,635 $18,614 $18,649

2,400 + $9,628 $22,178 $37,967 $11,088 $22,558 $19,674

Source: ERG estimates based on data in Tables 12 and 15.
20 

3.3 PRODUCTION SYSTEM FABRICATION AND INSTALLATION

BOEM resource evaluation engineers and socioeconomic analysts held multiple meetings to 

identify and include all costs while avoiding any overlaps between any pair of activity function 

costs. After resolving the detailed cost components needed within the estimates, BOEM

engineers provided: 

• Production structure costs, including the structure, production equipment, and infield 

flow lines. The production structures vary by water depth. For 0 to 60 m water depths, 

separate costs were developed for caissons, well protectors, and traditional fixed 

platforms. For 60 to 200 m water depths, the costs represented fixed platforms and spars. 

For all water depths beyond 200 m, the production systems are presumed to be floating 

structures (e.g. spar, semisubmersible, tension leg platform). The costs are the mean 

values for the distributions examined by the resource evaluation engineers. 

• Subsea costs, which include the mean values for subsea flowlines, umbilicals, manifolds, 

risers, and other equipment, as well as any additional costs needed on the 

platform/production system to which the subsea system is connected.

Table 17 shows the costs in 2010$ and 2008$ and the conversion to thousands of dollars. At 

this time, MAG-PLAN 2012 is structured for a single cost for each water depth. ERG took a 

60:40 weighted average of platform to caisson or well protector costs for systems in 0 to 60 m 

water depth based on the historical ratios of these production systems at that depth range. For 

subsea systems, ERG calculated a simple average of the three costs (Strellec 2011). 
21 

Table 17

Production System Costs

Data source Subgroup (m)

Representative 

Structure

Production 

Facility Structure

(Millions, 2010$) 

Production 

Facility Subsea 

(Millions, 2010$) 

2008$ 

(Millions)

MAG-PLAN 2012

(Thousands, 2008$) 

Costs From BOEM

GOMR ORE 

(2010$)

0–60 Fixed platform $7.899 $7.822

0–60 $5,758

Caisson or well 

protector $2.687 $2.661

60–200

Fixed platform 

or spar $17.271 $17.102 $17,102

200–400 Floating $100.003 $99.024 $99,024

400–800 Floating $180.591 $178.823 $178,823

800–1,600 Floating $364.454 $360.887 $360,887

1,600–2,400 Floating $571.271 $565.679 $565,679

2,400+ Floating $593.475 $587.666 $587,666

800–1,600

Subsea 

development $158.326 $156.78

$185,757

1,600–2,400

Subsea 

development $187.593 $185.76

2,400+

Subsea 

development $216.860 $214.74

200-800 Floating $138,924

Source: USDOI BOEM, 2011b. 
22 

3.4 ONSHORE GAS PROCESSING FACILITY 

ERG examined the semiannual worldwide construction survey published by the Oil & Gas 

Journal from November 2006 t hrough December 2010 (Kootungal 2006; 2007a,b; 2008a,b; 

2009a,b; and 2010a,b). ERG extracted the data for new gas processing plants in the United States 

for which the estimated cost was published. The date of the survey in which the project is first 

mentioned is the nominal year for the cost data. Table 18 lists the eight onshore gas processing 

projects identified through this search. The absence of projects in 2009 is understandable in light 

of the economic crisis that occurred in October 2008. ERG chose to include all of the projects 

listed, resulting in an overall average of $92.80 million (2008$) for new onshore gas processing 

projects.

Table 18

New Onshore Gas Processing Projects 2006–2010

Company Location Capacity 

(MMcf/d) Year

Cost 

(Nominal, 

millions)

Cost 

(Millions, 

2008$) 

Source

Energy Transfer 

Partners LP Johnson County, TX 115 2006 $65 $69.42 Kootungal 2006

CDM MAX 

LLC Cameron Parish, LA 600 2007 $15 $15.57 Kootungal 2007a

Devon Energy Calvin, OK 2007 $30 $31.14 Kootungal 2007b

Hiland Partners Woodford Shale, OK 40 2007 $23 $23.87 Kootungal 2007b

PVR Mistream Bethany Field, TX 80 2007 $20 $20.76 Kootungal 2007b

Enogex Clinton, OK 120 2008 $55 $55.00 Kootungal 2008b

Dominion 

Energy

Pleasants County, 

WV 10 2010 $253 $249.96 Kootungal 2010b

Occidental

Elk Hills oil and gas 

field, CA 200 2010 $280 $276.64 Kootungal 2010b

Average $92.80
23 

3.5 PIPELINE CONSTRUCTION

US DOE EIA maintains a Natural Gas Pipeline Project database (Gaul 2009; USDOE EIA 

2010b) and supplied a copy of the database for this project. ERG identified 12 na tural gas 

pipeline projects that were completed since 2005 in the offshore GOM planning areas that had an 

in-service year, cost in million dollars, and pipeline miles. ERG used several approaches to find 

water depth data for each project. Some water depths are taken from project descriptions. For 

others, ERG identified the OCS block in which the production structure was located and then 

found the water depth in that block. Not all water depth categories were represented in the data. 

ERG assumed a linear relationship between water depth and cost and performed a regression 

analysis on the data. The resulting equation was used to estimate the cost per mile for each depth 

category. 

Table 19 presents the estimated costs while Appendix A contains the data and detailed 

discussions. The costs range from $1,760,000 per mile for a pipeline in 0 to 60 m water depth to 

$2,380,000 per mile for a pipeline in water depths at or exceeding 2,400 m. MAG-PLAN 2012 is 

currently structured for a single pipeline construction cost; thus, ERG uses the midpoint value of 

$2,070,000 per mile.

Table 19

Estimated Cost per Mile by Water Depth (Thousands, 2008$)

Water Depth Range (m)

Water Depth 

Midpoint (m)

Cost Per Mile 

(Thousands, 2008$) 

0–60 30 $1,760

60–200 130 $1,780

200–400 300 $1,810

400–800 600 $1,880

800–1,600 1,200 $2,000

1,600–2,400 2,000 $2,170

2,400+ 3,000 $2,380

All depths $2,070

Source: ERG estimates

3.6 PLATFORM DECOMMISSIONING 

On October 15, 2010, BOEM (then known as BOEMRE) issued a N otice to Lessees and 

Operators (NTL) with guidance on d ecommissioning wells and structures (USDOI BOEMRE

2010c). In particular, the definition of when decommissioning takes place changes from one year 

after a lease terminates (i.e., a lease basis) to when a well or platform stops production for five

years or more (i.e., a well and structure basis). 

ERG used two recent publications to estimate decommissioning costs. Kaiser et al. (2009a,b) 

provides information on actual decommissioning costs for platforms in the GOM from 2003 to 

2008 in water depths ranging from 0 to approximately 90+ m (300+ ft). Proserv Offshore (2009) 

provides engineering estimates, based on representative platforms and structures in water depths 
24 

ranging from 400 to 8,000 feet (approximately 120 m to over 2,400 m). This latter report also 

focused strictly on GOM structures. 

Based on t hese reports, ERG estimated decommissioning costs for fixed platforms, spars, 

TLPs and mini-TLPs, and semisubmersibles. Appendix B contains the specific assumptions 

made for each structure type and water depth. 

The findings are presented in Table 20. Note that decommissioning with explosives is less 

expensive than decommissioning without explosives; however, decommissioning costs with 

explosives were available only for water depths up to 200 meters. The most expensive types of 

structures to decommission are those in water depths ranging from 200 to 800 m eters (e.g., 

TLPs, mini-TLPs, spars, fixed platforms). Floating production structures, such as 

semisubmersibles, are two to three times less expensive to decommission. 

Table 20

Cost of Platform/Structure Decommissioning in the GOM by Water Depth (Thousands, 2008$)

Water Depth

Assumed Type (a)

With 

Explosives

Without 

Meters Feet Explosives

0–60 0–200 Fixed Platform $1,528 $1,757

60–200 200–650 Fixed Platform $4,445 $5,111

200–400 650–1,300 Fixed Platform NA $40,525

400–800 1,300–2,600

Mini-TLP/Spar/Fixed

Platform NA $45,198

800–1,600 2,600–5,200 Semisubmersible/TLP/Spar NA $25,133

1,600–2,400 5,200–8,000 Semisubmersible/Spar NA $24,973

2,400+ 8000+ Semisubmersible NA $16,692

(a) In 400 to 800 m depths, 33 percent are assumed spars, 33 percent are assumed mini-TLPs, and 33 percent

are assumed fixed platforms, represented by one platform at 400 m. In 800 to 1,600 m depths, 4 percent are 

assumed semisubmersibles, 46 percent are assumed spars, 33 percent are assumed TLPs, and 17 percent are 

assumed mini-TLPs. In 1,600 to 2,400 m depths, 44 percent are assumed spars and 56 percent are assumed 

semisubmersibles (based on information collected by Proserv Offshore 2009). 

Source: Kaiser et al. 2009a,b; Proserv Offshore 2009. 
25 

3.7 PRODUCTION O&M

In MAG-PLAN 2012, annual production O&M costs are calculated on a p er-production 

system basis beginning with the year the system is installed and continuing for 15 years.14 These 

costs were generated by BOEM, GOMR ORE in order to be consistent with the data used to 

estimate the well and production structure costs (see Section 3.1.1 above for more details). Table 

21 presents the average costs in 2010$ and 2008$. A user can chose between average costs or 

high costs for wells and production costs in an E&D scenario but cannot mix cost types (e.g., 

high well costs with average production costs) within a run without specifically editing a cost file 

to reflect this.

Table 21

Average and High O&M Cost Per Production System by Water Depth (Thousands, 2008$)

Average High

Water 

Depth 

(m) Representative System

Annual 

Operating Cost 

(Thousands, 

2010$)

Annual 

Operating Cost 

(Thousands, 

2008$)

Annual 

Operating Cost 

(Thousands, 

2010$)

Annual 

Operating Cost 

(Thousands, 

2008$)

0–60 

Caisson, well protector, 

or platform $979.0 $969.0 $1,668.9 $1,653.0

60–200 Fixed platform or spar $979.0 $969.0 $1,668.9 $1,653.0

200–400 Floater $4,290.8 $4,249.0 $12,006.9 $11,889.0

400–800 Floater $4,290.8 $4,249.0 $12,006.9 $11,889.0

800–

1,600 

Floater

$10,652.2 $10,548.0 $43,267.5 $42,844.0

1,600–

2,400 

Floater

$10,652.2 $10,548.0 $43,267.5 $42,844.0

2,400+ 

Floater $10,652.2 $10,548.0 $43,267.5 $42,844.0

Subsea development $4,290.8 $4,249.0 $12,006.9 $11,889.0

200–800 Floater $4,290.8 $4,249.0 $12,006.9 $11,889.0

Source: USDOI BOEM, 2011b 

 

14 The previous version of MAG-PLAN used a per-well basis for production O&M costs.
26 

3.8 ONSHORE GAS PROCESSING O&M

ERG had difficulty identifying O&M costs for onshore gas processing facilities. Many of 

them are part of large, integrated companies and, although financial data for the companies might 

be publicly available, even the segment data is too consolidated to use for this purpose. In recent 

years, there has been a growth in “midstream” companies that focus on the gathering, processing, 

and transport of natural gas and natural gas liquids. Many of these companies, such as WTG Gas 

Processing, are private, and financial data are not available.

Targa Resources Partners, L.P. meets the criteria of being a publicly traded company that has 

a segment in natural gas gathering and processing (Targa Resources Partners LP 2009). Table 22

lists the operating costs and volumes processed for 2009, 2008, and 2007. The cost to process a 

Bcf ranges from $315,800 in 2009 to $359,700 in 2008, with 2007 costs falling within this range. 

MAG-PLAN 2010 uses the 2008 value of $359,700 Bcf for onshore gas processing O&M costs. 

Table 22

Estimated Onshore Gas Processing O&M Costs

Year

Parameter 2009 2008 2007

Source 

(page)

Operating Expenses (Millions) $51.4 $55.3 $50.9 70

Volume of Gas Processed (MMcf/Day) 445.9 421.2 429.3 70

Convert to Bcf/year 162.8 153.7 156.7

Convert to $/Bcf $315,815 $359,703 $324,836

MAG-PLAN 2010 (Thousands/Bcf, 2008$) $359.7

Source: Targa Resources Partners LP 2009

3.9 PIPELINE OPERATIONS AND MAINTENANCE

The Oil & Gas Journal (OGJ) printed a special report on pipelines in September 2009 with 

fiscal year 2008 data. The detailed tables listed the gas volumes transported for others in MMcf 

as well as the O&M costs. ERG cross-referenced the company names in the OGJ tables against 

those in BOEM’s company list (USDOI BOEMRE 2010d) to identify companies with offshore 

operations in the GOM. Table 23 summarizes the data. The average annual O&M cost by 

volume transported is $28,000 per MMcf or $28,000,000 per Bcf.15This value is used for all 

water depths because the data are presented on a company basis, that is, aggregated over all 

pipeline depths operated by the company. 

 

15 USDOI MMS 2005 lists units of $/mile on pages xix and 5, and $/Bcf/year in Table 2-9 on p. 15. The values 

in Table 2-9 are more likely to be in thousands of dollars per Bcf per year. These range from $59,000 to $87,000. 

That is, the revised estimates are about three to five times higher. 
27 

Table 23 Offshore Pipeline Operating Costs (2008$)

Company

Volumes 

MMcf

O&M expense 

(Thousands) 

O&M Cost 

Thousands/MMcf

Algonquin Gas Transmission LLC 351,104 $77,998 $0.222

Alliance Pipeline LP 640,863 $66,315 $0.103

ANR Pipeline Co. 1,982,666 $292,042 $0.147

Black Marlin Pipeline Co. 516 $2,020 $3.915

Chandeleur Pipe Line Co. 29,554 $3,007 $0.102

Columbia Gulf Transmission Co. 993,349 $58,643 $0.059

Dauphin Island Gathering Partners 59,670 $8,030 $0.135

Desting Pipeline Co. LLC 284,717 $20,178 $0.071

Discovery Gas Transmission LLC 257,070 $5,384 $0.021

Dominion Transmission Inc. 620,055 $392,254 $0.633

El Paso Natural Gas Co. 1,740,860 $223,714 $0.129

Enbridge Offshore Pipelines (UTOS) LLC 47,311 $4,403 $0.093

Enbridge Pipelines (MidLa) LLC 36,241 $4,113 $0.113

Florida Gas Transmission Co. LLC 785,975 $93,532 $0.119

Garden Banks Gas Pipeline LLC 58,234 $3,916 $0.067

Gulf South Pipeline Co. LP 1,048,042 $148,122 $0.141

Gulf Stream Natural Gas System LLC 297,821 $18,269 $0.061

High Island Offshore Systems LLC 108,286 $25,074 $0.232

Mississippi Canyon Gas Pipeline LLC 160,453 $3,351 $0.021

Natural Gas Pipeline Co. of America 1,925,335 $599,021 $0.311

Nautilus Pipeline Co. LLC 63,049 $5,991 $0.095

Northern Natural Gas Co. 1,143,582 $260,722 $0.228

Panhandle Eastern Pipe Line Co. LP 701,616 $161,150 $0.230

Panther Interstate Pipeline Energy LLC 4,034 $890 $0.221

Sabine Pipe Line LLC 250,187 $13,480 $0.054

Sea Robin Pipeline Co. LLC 126,293 $14,297 $0.113

Southern Natural Gas Co. 879,172 $184,947 $0.210

Tennessee Gas Pipeline Co. 1,801,283 $412,888 $0.229

Texas Eastern Transmission LP 1,432,742 $397,165 $0.277

Texas Gas Transmission LLC 867,664 $105,696 $0.122

Transcontinental Gas Pipe Line Co. LLC 2,577,642 $542,623 $0.211

Trunkline Gas Co. LLC 643,316 $69,052 $0.107

Venice Gathering System LLC 22,560 $10,449 $0.463

Average $0.280

Source: OGJ 2009
28 

3.10 SECTOR ALLOCATION FOR NEW ACTIVITY FUNCTIONS

ERG assumes that G&G prospecting falls entirely (100 percent) within IMPLAN sector 369 

(architectural, engineering and related services) and that subsea systems fall entirely within 

IMPLAN sector 206 (Mining and oil and gas field machinery).

ERG allocated an FPSO to two IMPLAN sectors: 209 (Shipbuilding and repairing) (90.48 

percent) and 206 (Mining and oil and gas field machinery) (9.52 percent), based on the assumed 

FPSO activity function consisting of the vessel plus subsea system. A typical cost for a FPSO 

vessel is $1.9 billion and that of a subsea system is $200 million (see Appendix C for details). 

4.0 LAB OR COS T PER CE NTAGE S

As explained in Chapter 2.0, the activity costs are split into labor and non-labor categories. 

Labor dollars go to households, where they are spent both within and outside of the region. 

Activity costs are presented in Chapter 3.0. Chapter 4.0 examines the percent of total activity 

costs formed by labor. 

For activity functions where we have sufficient data, ERG developed composite labor shares 

that are aggregates of the different commodities and services that make up the activity. This was 

possible for drilling exploratory, nonproductive, and productive wells, as well as production 

O&M costs (see Section 4.1). 

For the remaining activities, ERG identified the most appropriate NAICS code for each 

activity and downloaded 2007 Economic Census data from the U.S. Bureau of the Census for 

that code. The ratio of payroll to total revenues is the estimate of the labor share. These activities 

are discussed in Section 4.2. Section 4.3 contains some observations on how the labor share 

estimates for drilling wells compares with the values in earlier studies.

4.1 ACTIVITY FUNCTIONS WITH COMPOSITE LABOR SHARES

4.1.1 Exploratory Well Drilling

The derivation of the labor share for wells is based on ERG (2011), which examined the role 

of service industries in offshore oil and gas activities in the GOM (see Table 24). The report took 

detailed cost data for “typical” deep offshore exploratory and development wells published in 

USDOE NETL (2005), grouped entries into service industries and commodities, and 

reconfigured them into IMPLAN sectors. No labor percentage is assigned to the commodity 

costs, and 100 percent was assigned to the company and contract labor line items.

The “percent” column in Table 24 lists the percentage of total costs by each service industry 

and commodity that contributes to drilling an exploratory well based on the data in USDOE 

NETL (2005). The next three columns are the revenues, payroll, and ratio of payroll-to-revenues 

based on the 2007 Economic Census (U.S. Census Bureau 2011). The ratio of payroll revenues

provides the estimated initial labor share for that industry. The labor share for the industry is 

multiplied by the percentage of well costs represented by the industry to calculate the adjusted 

labor share. The rest of the cost for that industry goes to the IMPLAN sector as a n on-labor 

expenditure. 

When summed, the adjusted labor percentages result in a weighted average estimate of the 

household income from exploratory drilling operations. In Table 24, for every dollar spent in an 

exploratory drilling activity, 19.91 cents go to households and 80.09 cents are distributed among 
29 

the 14 IMPLAN sectors. So as not to overstate the precision of the estimate, ERG assigned 20 

percent as the labor share for drilling an exploratory well. 

Table 24

Derivation of Labor Share for Exploratory Drilling

 

Census Data 

(Million$) 

Initial

Labor

Adjusted

Labor

Percent to 

IMPLAN 

Sector Name NAICS Percent Revenues Payroll Share Share Sector

Drilling Oil and Gas Wells 213111 42.88% $22,201 $5,888 26.5% 11.37% 31.51%

Support Activities for Oil 

and Gas Operations 213112 11.37% $45,754 $12,374 27.0% 3.08% 8.30%

Architectural and 

Engineering Services 541300 1.25% $254,201 $97,560 38.4% 0.48% 0.77%

Air Transportation 481000 1.12% $146,459 $26,438 18.1% 0.20% 0.92%

Water Transportation 483000 6.67% $34,271 $4,041 11.8% 0.79% 5.88%

Truck Transportation 484000 0.85% $217,895 $57,346 26.3% 0.22% 0.63%

Other Accommodations 721A00 0.35% $180,308 $46,043 25.5% 0.09% 0.26%

Oil and Gas Field 

Equipment and Machinery 333132 3.74% $16,504 $2,495 15.1% 0.56% 3.17%

COMMODITY EXPENDITURES (NO LABOR) *

Iron and Steel Mills 331111 11.00% 11.00%

Cement Manufacturing 327310 2.78% 2.78%

Gasoline Stations 447000 2.65% 2.65%

Water, Sewage, and Other 

Systems 221300 0.14% 0.14%

Power Generation and 

Supply 221100 0.18% 0.18%

 

Insurance Carriers 524100

11.92

% 11.92%

 

Wages 3.12% 100.0% 3.12%

Total 100.00% 19.91% 80.09%

*This is not to say there is no labor associated with the commodities, however, these jobs would not be directly 

associated with the labor located in the GOM for the drilling activities. It is the latter which we are estimating in this 

table. The jobs associated with commodities would appear as the indirect effect jobs for drilling. 

Sources: ERG 2011; U.S. Census Bureau 2011; USDOE NETL 2005 
30 

4.1.2 Nonproductive Development Well Drilling

Table 25 repeats the calculations, but with the cost percentage profile for a nonproductive 

development well. For every dollar spent in drilling an offshore development well, 24.24 cents 

go to households and 75.76 c ents are distributed among 14 ot her IMPLAN sectors. ERG 

assigned 24 percent as the labor share for drilling a nonproductive development well. 

Table 25

Derivation of Labor Share for Nonproductive Development Drilling

 

Census Data 

(Million$) 

Initial

Labor

Adjusted

Labor

Percent to 

IMPLAN

Sector Name NAICS Percent Revenues Payroll Share Share Sector

Drilling Oil and Gas Wells 213111 34.48% $22,201 $5,888 26.5% 9.14% 25.34%

Support Activities for Oil and 

Gas Operations 213112 21.97% $45,754 $12,374 27.0% 5.94% 16.03%

Architectural and Engineering 

Services 541300 1.86% $254,201 $97,560 38.4% 0.72% 1.15%

Air Transportation 481000 0.91% $146,459 $26,438 18.1% 0.16% 0.75%

Water Transportation 483000 7.58% $34,271 $4,041 11.8% 0.89% 6.69%

Truck Transportation 484000 0.84% $217,895 $57,346 26.3% 0.22% 0.62%

Other Accommodations 721A00 0.52% $180,308 $46,043 25.5% 0.13% 0.39%

Oil and Gas Field Equipment 

and Machinery 333132 9.78% $16,504 $2,495 15.1% 1.48% 8.30%

COMMODITY EXPENDITURES (NO LABOR)* 

Iron and Steel Mills 331111 10.27% 10.27%

Cement Manufacturing 327310 2.52% 2.52%

Gasoline Stations 447000 2.19% 2.19%

Water, Sewage, and Other 

Systems 221300 0.11% 0.11%

Power Generation and Supply 221100 0.16% 0.16%

 

Insurance Carriers 524100 1.26% 1.26%

Wages 5.55% 100.0% 5.55%

 

Total 100.00% 24.24% 75.76%

*This is not to say there is no labor associated with the commodities, however, these jobs would not be directly 

associated with the labor located in the GOM for the drilling activities. It is the latter which we are estimating in this 

table. The jobs associated with commodities would appear as the indirect effect jobs for drilling. 

Sources: ERG 2011; U.S. Census Bureau 2011; USDOE NETL 2005
31 

4.1.3 Productive Development Well Drilling

The difference between a nonproductive well and a productive well is that the latter includes 

completion and lease equipment costs. ERG assigns these costs to NAICS 333132—oil and gas 

field equipment and machinery. For most well depth/water depth combinations, completion and 

equipment costs typically add about 4 percent to the cost of a nonproductive well (see Section 

3.1.4). 

Table 26 adds 4 percent to the oil and gas field equipment and machinery sector for a total of 

13.8 percent of costs for a productive development well. The percentages for the other services 

and commodities are reduced proportionately so that the percentages sum to 100. For every 

dollar spent in drilling a productive offshore development well, 23.84 cents go to households and 

76.16 cents are distributed among 14 other IMPLAN sectors. ERG uses 24 percent as the labor 

share for drilling a productive development well. 
32 

Table 26

Derivation of Labor Share for Productive Development Drilling

 Census Data (Million$) 

Initial

Labor

Adjusted 

Labor

Percent 

to 

IMPLAN

Sector Name NAICS Percent Revenues Payroll Share Share Sector

Drilling Oil and Gas Wells 213111 32.95% $22,201 $5,888 26.5% 8.74% 24.21%

Support Activities for Oil and 

Gas Operations 213112 21.00% $45,754 $12,374 27.0% 5.68% 15.32%

Architectural and Engineering 

Services 541300 1.78% $254,201 $97,560 38.4% 0.68% 1.10%

Air Transportation 481000 0.87% $146,459 $26,438 18.1% 0.16% 0.72%

Water Transportation 483000 7.25% $34,271 $4,041 11.8% 0.85% 6.39%

Truck Transportation 484000 0.80% $217,895 $57,346 26.3% 0.21% 0.59%

Other Accommodations 721A00 0.49% $180,308 $46,043 25.5% 0.13% 0.37%

Oil and Gas Field Equipment 

and Machinery 333132 13.78% $16,504 $2,495 15.1% 2.08% 11.69%

COMMODITY EXPENDITURES (NO LABOR)* 

Iron and Steel Mills 331111 9.82% 9.82%

Cement Manufacturing 327310 2.41% 2.41%

Gasoline Stations 447000 2.09% 2.09%

Water, Sewage, and 

Other Systems 221300 0.10% 0.10%

Power Generation and 

Supply 221100 0.15% 0.15%

 

Insurance Carriers 524100 1.20% 1.20%

Wages 5.30% 100.0% 5.30% 

 

Total 100.00% 23.84% 76.16%

*This is not to say there is no labor associated with the commodities, however, these jobs would not be directly 

associated with the labor located in the GOM for the drilling activities. It is the latter which we are estimating in this 

table. The jobs associated with commodities would appear as the indirect effect jobs for drilling. 

Sources: ERG 2011; U.S. Census Bureau 2011; USDOE NETL 2005
33 

4.1.4 Comparison of Labor Share Estimates for Well Drilling

ERG found no data to support varying the percentage by well depth and water depth. Table 

27 compares the values from this report, the 2005 model documentation, and Dismukes et al. 

2003 (as reported in USDOI MMS 2005). 

Table 27

Comparison of Labor Percentages for Drilling Wells

Labor Percentages

Source Exploratory

Nonproductive 

Development Development

This report 20% 24% 24%

USDOI MMS 2005 35%–40% 22%–27% 20%–27%

Dismukes et al. 2003 <10% <10% <10%

The estimates derived for this report are twice as large as those in Dismukes et al. 2003 for 

all well types. For productive and nonproductive development wells, the new estimates are in the 

middle of the range estimated in the previous model documentation (USDOI MMS 2005). The 

largest difference is for exploratory wells. The new estimate has the labor share being smaller for 

an exploratory well than a development well, while previously it was the converse. There was a 

steep cost increase in well drilling between 2002 and 2008 ( see API 2008 and 2010). The 

increase could be due to a variety of factors, such as increased interest in drilling in deep and 

ultra-deep water areas, or advanced technologies (horizontal drilling, measurement while 

drilling, or other technologies to gather information about the formation). Labor costs might 

form a much smaller percentage of the additional costs for these technologically advanced 

methods. That is, it might be much more expensive to drill the well, but without a comparable 

increase in the amount of manpower to do it. 

4.1.5 Production O&M

The USDOE EIA report, Oil and G as Lease Equipment and O perating Costs 1994–2009, 

presents costs for fixed platforms in the GOM at 100-ft depth, 300-ft depth, and 600-ft depth and 

for two sizes: a 12-slot and an 18-slot platform (USDOE EIA 2010a). Table 28 arranges the data 

to compare cost components that vary with water depth, while Table 29 arranges the data to 

compare cost components that vary with the number of well slots. 

4.1.5.1 Costs That Vary By Water Depth

Table 28 indicates that the following variables are unaffected by water depth for a given 

platform size:

• Labor

• Supervision 

• Payroll Overhead

• Food Expense 
34 

Labor transportation costs vary by water depth because the latter is approximately related 

to distance from shore. There is a 3 percent increase in transportation costs in moving from the 

100-ft depth to 300-ft depth but only an additional 1 percent increase to move from the 300-ft 

depth to the 600-ft depth.16

 

16 Notes on distance assumptions: a review of water depths off the coasts of Louisiana and Texas indicates that 

water depths increase gradually out to about 50 nautical miles from shore (closer in eastern Louisiana and Texas 

waters), at which point depths quickly go from 100 m to greater than 400 m as the edge of the continental shelf is 

reached. Therefore, transportation costs from shore to 200–400 m water depths should not rise substantially from 

that seen in the 100–200 m water depth range. 
35 

Table 28

Cost Comparison by Water Depth

2008 Costs 12-slot 18-slot Ratio of 300 ft 

to 100 ft costs

Ratio of 

600 ft to 

300 ft 

costs

0–60 m 

(100 ft)

60–200 m 

(300 ft)

No 

Change

0–60 m 

(100 ft)

60–200 m 

(300 ft)

60–200 m 

(600 ft)

No 

Change 12-slot 18-slot 18-slot

Labor $1,171,600 $1,171,600 * $1,291,400 $1,291,400 $1,291,400 * 

Supervision $175,700 $175,700 * $193,700 $193,700 $193,700 * 

Payroll Overhead. $538,900 $538,900 * $594,000 $594,000 $594,000 *

Food Expense $122,600 $122,600 * $140,200 $140,200 $140,200 *

Labor Transportation $3,045,300 $3,142,000 $3,045,300 $3,142,000 $3,175,200 1.03 1.03 1.01

Surface Equipment $201,400 $201,400 * $201,400 $201,400 $229,700 1.14

Operating Supplies $40,300 $40,300 * $40,300 $40,300 $45,900 1.14

Workover $2,502,100 $2,620,200 $3,753,200 $3,930,300 $4,003,300 1.05 1.05 1.02

Communications $57,800 $59,000 $77,000 $77,800 $78,200 1.02 1.01 1.01

Administrative $565,300 $565,300 * $613,200 $613,200 $626,800 1.02

Insurance $412,400 $464,800 $605,000 $645,400 $1,037,400 1.13 1.07 1.61

Total $8,833,400 $9,101,800 $10,554,700 $10,869,700 $11,415,800 

Source: USDOE EIA 2010a
36 

Table 29

Cost Comparison by Number of Well Slots

Water Depth

0–60 m (100 ft) 60–200m (300 ft)

2008 Costs 12-slot 18-slot Change 12-slot 18-slot Change

 

Labor $1,171,600 $1,291,400 1.10 $1,171,600 $1,291,400 1.10

Supervision $175,700 $193,700 1.10 $175,700 $193,700 1.10

Payroll Overhead $538,900 $594,000 1.10 $538,900 $594,000 1.10

Food Expense $122,600 $140,200 1.14 $122,600 $140,200 1.14

Labor Transportation $3,045,300 $3,045,300 $3,142,000 $3,142,000 

Surface Equipment $201,400 $201,400 $201,400 $201,400

Operating Supplies $40,300 $40,300 $40,300 $40,300

Workover $2,502,100 $3,753,200 1.50 $2,620,200 $3,930,300 1.50

Communications $57,800 $77,000 1.33 $59,000 $77,800 1.32

Administrative $565,300 $613,200 1.08 $565,300 $613,200 1.08

Insurance $412,400 $605,000 1.47 $464,800 $645,400 1.39

Total $8,833,400 $10,554,700 $9,101,800 $10,869,700 

Source: USDOE EIA 2010a

Surface equipment costs do not change for water depths ≤ 300 ft, but a 14 percent increase 

is seen when moving from 300-ft to 600-ft water depths. Workover costs increase by 5 percent 

between the 100-ft and 300-ft water depths and by only an additional 2 percent from the 300-ft 

depth to the 600-ft depth. Communications change minimally (i.e., an increase by 1 to 2 percent

depending on the number of platforms and water depth). Administrative costs do not change for 

water depths ≤ 300 ft, but a 2 percent increase is seen when moving from 300-ft to 600-ft water 

depths. 

Insurance costs increase with water depth. For a 12-slot platform, insurance costs increase 

by 13 percent between the 100-ft and 300-ft water depths. For an 18-well platform, insurance 

costs increase by 7 percent between the 100-ft and 300-ft water depths, so there appears to be 

some economies of scale when the platform is located in water depths of 300 feet or less. When 

an 18-slot platform moves from 300-ft to 600-ft water depths, however, insurance costs increase 

by 61 percent—the largest change seen in any of the parameters.

4.1.5.2 Costs That Vary by the Number of Well Slots

Table 29 holds the water depths constant but varies the number of well slots. As anticipated there 

is no c hange in the costs for labor transportation, but there is also no change in the costs for 

surface equipment, or operating supplies. 
37 

We see some economies of scale in the data in Table 29 as the number of well slots increases 

from 12 to 18 (i.e., a 50 percent increase). Only workover costs show a comparable 50 percent

increase when the number of well slots increases from 12 to 18. Labor, supervision, and payroll 

overhead increase by only 10 percent, while administrative costs increase by 8 percent. Food 

expenses increase by 14 percent.

17

4.1.5.3 O&M Costs by Labor and Non-Labor Components

Communication costs increase by about a third, and insurance 

increases between 39 and 47 percent. 

ERG interpolated the EIA Cost Study Report data to estimate O&M costs for a four-well 

structure in 0 to 60 m water depth, 6-slot structures in 60 m and 200 m water depths, and a 12-

well structure at 200 to 400m water depth and examined the percentage of the costs formed by 

labor expenses (see Table 30). Labor share is the sum of labor, supervisory, and administrative 

costs. Administrative costs are assumed to represent the onshore labor costs that support the 

offshore operations. Payroll overhead is not included in labor share because it is not available for 

the employees to spend. 

Table 30

Production O&M Costs

 0–60 m 60–200 m 60–200 m 200–400 m

2008 Cost Items 4 Slots 6 Slots 6 Slots 12 Slots

Labor Share 25.4% 22.3% 21.4% 19.5%

Payroll Overhead 7.1% 6.2% 5.9% 5.5%

Food Expense 1.5% 1.4% 1.4% 1.2%

Labor 

Transportation 46.4% 40.1% 38.6% 31.7%

Surface Equipment 3.1% 2.6% 2.8% 2.6%

Operating Supplies 0.6% 0.5% 0.6% 0.5%

Workover 12.7% 22.3% 22.3% 26.6%

Communications 0.5% 0.6% 0.6% 0.6%

Insurance 2.8% 4.0% 6.5% 11.9%

Total 100.0% 100.0% 100.0% 100.0%

Source: ERG estimates.

The largest change is the increase in the cost of insurance, which grows from 2.8 percent in 

the 0–60 m water depth category to nearly 12 percent for a structure in 200–400 m water depth. 

The percentage nearly doubles as the water depth goes from 60–200 m to 200–400 m. At 400 m, 

operations have left the shelf and are moving down the slope to the deepwater regions. The 

pattern of insurance costs is consistent with increased risks with deeper waters. The jump in 

insurance costs as a percentage of overall costs results in all but one cost item showing relative 

decreases with increasing water depth. The exception is workover costs that increase 

monotonically but not necessarily proportionately with the number of wells. 

 

17 Perhaps due to the need for another person on the kitchen staff to serve the additional crew members.
38 

USDOE EIA (2010a) does not provide operating cost data for deeper waters. As a result, 

ERG had no basis for extrapolating how the proportion of cost items changed for depths greater 

than 400 m. In effect, we assume that the proportions stay the same while the absolute value of 

the O&M costs increases in the slope and deepwater regions. Production O&M, therefore, is the 

only activity for which ERG can develop labor shares that differ by water depth. Labor shares 

are 25 percent, 22 percent, and 20 percent for 0–60 m, 60–200 m, and >200 m water depths, 

respectively. 
39 

4.2 LABOR SHARES FOR REMAINING ACTIVITIES

For the remaining activities, ERG identified the most appropriate NAICS code for each 

activity and downloaded 2007 E conomic Census national data from the U.S. Bureau of the 

Census for that code (Table 31). The ratio of payroll to revenues is the estimated labor share. The 

exception is offshore pipeline O&M, where we used the state data for Louisiana.18

Table 31

Labor Shares by Activity

Water Closest

Census Data 

(Million$)

Activity Depth (m) NAICS Revenues Payroll Labor Share

Exploratory Drilling all composite 20%

Nonproductive Development Drilling all composite 24%

Development Drilling and Production all composite 24%

G&G Prospecting all 541360 $3,093 $791 26%

Platform Fabrication and Installation all 336611 $17,234 $4,618 27%

FPSO all 336611 $17,234 $4,618 27%

Subseabed all 333132 $16,504 $2,495 15%

Onshore Gas Processing Construction all 237120 $30,295 $8,947 30%

Offshore Pipeline Construction all 237120 $30,295 $8,947 30%

Decommission Platform (explosives) all 238910 $85,524 $19,119 22%

Decommission Platform (no 

explosives) all 238910 $85,524 $19,119 22%

Onshore Oil Spill all 562910 $12,632 $3,512 28%

Offshore Oil Spill all 562910 $12,632 $3,512 28%

Production O&M

0–60 composite 25%

60–200 composite 22%

200–400 composite 20%

400–800 composite 20%

800–1,600 composite 20%

1,600–2,400 composite 20%

2,400+ composite 20%

Onshore Gas Processing O&M all 211112 $42,363 $501 1%

Offshore Pipeline O&M (LA) all 486210 $1,283 $114 9%

Source: U.S. Census Bureau 2011

 

18 The labor share for Texas was very close to the national average of 16 percent; hence, ERG considered the 

Texas data to be more representative of onshore pipelines than offshore pipelines.
40 

5.0 ONS HOR E DIS TR IB UTIONS 

As was discussed in Chapter 2.0, the first stage of MAG-PLAN takes the money that is spent 

by oil and gas operations on activities in the GOM OCS region and: 

• Calculates the spending into activities

• Divides the spending from activities into IMPLAN industry sectors

• In effect, identifies where the spending would come onshore by industry sector 

The result is a matrix of spending by industry by user-defined onshore geographical region, 

or economic impact area (EIA). The Stage 1 output becomes the Stage 2 input, where the direct, 

indirect, and induced jobs and output supported by that spending are estimated through the use of 

IMPLAN multipliers. 

MAG-PLAN v2 (USDOI MMS 2005) was structured to evaluate impacts on three Texas 

EIAs, four Louisiana EIAs, four Florida EIAs, one Alabama EIA, one Mississippi EIA, one 

“Other GOM” EIA that contained all the counties and parishes not included in the EIA already 

defined, and an “Other U.S.” region for the remaining 45 states and the District of Columbia. 

One of the enhancements to MAG-PLAN 2012 is the ability to define new geographic areas of 

interest (or EIAs) within the model based on new research on the relationships between counties 

and parishes. This enhancement necessitates the development of a methodology to distribute the 

spending in the GOM OCS to geographic areas as small as an individual county or parish as well 

as to the rest of the world. MAG-PLAN 2012, for example, splits the “Other GOM EIA” into 

five EIAs–Rest of Texas, Rest of Louisiana, Rest of Mississippi, Rest of Alabama, and Rest of 

Florida—that contain the counties and parishes not in the EIAs already defined.

In other words, to complete the third bullet listed above, a 440 b y n matrix (440 industry 

sectors by n geographic areas) was developed, where the row totals sum to 100 percent. 

A combination of two approaches is used to estimate the onshore distribution of spending on 

activities in the GOM OCS region: a “top down” approach and a “bottom up” approach, 

geographically speaking (i.e., from larger to smaller geographic units or vice versa). These 

approaches are used 1) to provide information that IMPLAN is not designed to provide (using 

the top-down approach) or 2) to tailor the distributions of certain industries of particular 

importance to offshore oil and gas operations (using the bottom-up approach). 

For the top-down approach, ERG uses IMPLAN’s “regional purchase coefficients” (RPCs) 

as proxies to estimate the proportion of demand supplied from sources within the region. This 

simplification does not include all the trading considerations that IMPLAN calculates for a 

“regional share” or (RS). The RS is used in a binary decision calculation—demand that is not 

supplied by a region must be supplied from outside the region and can be calculated as (1-RS) 

for any region. 

The direct use of IMPLAN RPCs does not work to answer all the questions regarding where 

GOM OCS dollars are spent within certain regions, particularly the most important immediate 

area bordering the GOM. IMPLAN provides the user with the internal demand for a region, 

which is supplied within the region, but not the proportion of demand for the entire region met 

by any subset of the region. For example, if an IMPLAN model calculates the RS for the fivestate GOM region (comprising Texas, Louisiana, Mississippi, Alabama, and Florida), it does not 

provide the portion of the five-state supply that is contributed by Texas, for example. 
41 

Alternatively, an IMPLAN model for the state of Texas calculates the RS of the state’s demand 

provided by the state’s supply, but this approach also cannot provide Texas’ supply contribution 

relative to the five-state supply. An approach was developed to calculate a w eighted average 

contribution from each state to the five-state supply that uses the RSs from all five of the state 

IMPLAN models as well as RSs from the five-state region model to address this situation. 

Section 5.2 walks the reader through the top-down calculations. 

The bottom-up approach addresses the issues inherent in a national model (e.g. IMPLAN). 

Because IMPLAN is a national model, its underlying data reflect all operations in the nation. 

However, there are certain industries for which a n ational model cannot adequately represent 

spending patterns in the offshore GOM OCS region. For example, IMPLAN Sector 209 i s 

shipbuilding. There are major shipbuilding facilities on the East and West Coasts as well as in 

the GOM. However, fixed platforms and parts of floating production systems will be 

manufactured in the GOM, not on the East or West Coasts. Thus, the top-down approach is not 

appropriate for this sector. To tailor the analysis for offshore oil and gas operations in the GOM

region, a bottom-up approach to tailor the onshore distributions of certain sectors important to 

offshore oil and gas operations is used. For specific industries, a detailed analysis of the 

businesses and locations offering these services and commodities (ERG 2011) was expanded for 

the industry sectors considered as part of this study. See Section 5.3 for details. 

Section 5.1 discusses in detail the different areas considered within MAG-PLAN v3. Section 

5.2 addresses the top-down approach for apportioning GOM OCS spending to the key areas of 

interest. Section 5.3 summarizes the bottom-up approach and presents how the detailed onshore 

distributions were derived and the sectors for which they were developed. Section 5.4 discusses 

the different onshore distributions used for labor spending. Methods to modify the Gulf-wide 

matrix to reflect the Western and Central GOM planning areas are discussed in Section 5.5. 
42 

5.1 ONSHORE AREAS OF INTEREST

Figure 2 is the first in a series of conceptual illustrations of the onshore geographic areas of 

interest. The circle defines the border between the United States and the Rest of World (ROW). 

The combined area inside of the circle represents the amount of domestic demand that is 

provided by domestic supply. The area outside of the largest circle represents the amount of 

domestic demand met by imports.

In Figure 3, the inner circle represents the five-state GOM region of Texas, Louisiana, 

Mississippi, Alabama, and Florida. The space between the inner circle and the outer circle 

represents the Rest of the United States. 

Figure 2. United States and the ROW

Figure 3. Five-State GOM Region and the Rest of the United States
43 

In Figure 4, t he five-state GOM region is the larger circle, while the green inner circle 

represents the subset of individual counties and parishes within the five states that are the 

likeliest to be affected by spending on activities in the offshore GOM (“Gulf coast economic 

impact area”). In MAG-PLAN v3, this subset of counties and parishes can be joined into regions

or BOEM-defined economic impact areas (EIAs). The space between the GOM counties and the 

rest of the state is the “Rest of [State]” region. In Figure 4, the Texas GOM counties are 

represented by the green wedge between the dotted lines indicating the boundaries between 

Florida, Texas, and Louisiana. The Rest of Texas is the gray area indicated by the double-headed 

arrow.

Figure 4. GOM counties and parishes, rest of state regions 

within the five-state GOM Region. 

Figure 5 is the composite summary of the different regions considered within MAG-PLAN 

2012. 

Tables 32 through 35 list the 189 counties and parishes that can be included and grouped into 

economic impact areas (EIAs). The only constraint is that each EIA must lie within a single state. 

In this section, for simplicity, the set of 189 c ounties and parishes is called the “Gulf coast 

economic impact area.” That is, the “Five-State GOM” refers to the entirety of the five states 

(i.e., both the green and light gray regions in Figure 5), while the “Gulf coast economic impact 

area” refers to 189 counties and parishes that can be included and grouped in to BOEM-defined 

EIAs (i.e., only the green region in Figure 5). In addition to the BOEM-defined EIAs, results can 

be reported for the Rest of State for each of the 5 GOM states, Rest of U.S., and Rest of World. 
44 

Figure 5. MAG-PLAN 2012 geographic regions of interest. 

Table 32

Texas: 63 Counties That Can Be Included in the Gulf Coast Economic Impact Area

Angelina Colorado Jackson Matagorda Trinity

Aransas Dewitt Jasper McMullen Tyler

Austin Duval Jefferson (TX) Montgomery Victoria

Bastrop Fayette Jim Hogg Newton Walker

Bee Fort Bend Jim Wells Nueces Waller

Brazoria Galveston Karnes Orange Washington

Brazos Goliad Kenedy Polk Webb

Brooks Gonzales Kleberg Refugio Wharton

Burleson Grimes La Salle Sabine Willacy

Caldwell Guadalupe Lavaca San Augustine Wilson

Calhoun Hardin Lee San Jacinto Zapata

Cameron (TX) Harris Liberty San Patricio

Chambers Hidalgo Live Oak Starr

Source: USDOI MMS (2005) and Fannin et al. (2011).
45 

Table 33

Louisiana: 40 Parishes That Can Be Included in the Gulf Coast Economic Impact Area

Acadia East Baton Rouge Lafourche St. Bernard St. Tammany

Allen East Feliciana Livingston St. Charles Tangipahoa

Ascension Evangeline Natchitoches St. Helena Terrebonne

Assumption Iberia Orleans St. James Vermilion

Avoyelles Iberville Plaquemines St. John the Baptist Vernon

Beauregard Jefferson (LA) Pointe Coupee St. Landry Washington

Calcasieu Jefferson Davis Rapides St. Martin West Baton Rouge

Cameron (LA) Lafayette Sabine St. Mary West Feliciana

Source: USDOI MMS (2005) and Fannin et al. (2011).

Table 34

Mississippi and Alabama Counties that Can Be Included in the Gulf Coast Economic Impact Area

15 Mississippi Counties 17 Alabama Counties

Amite Marion Baldwin Houston

Forrest Pearl River Butler Lowndes

George Perry Choctaw Marengo

Greene Pike Clarke Mobile

Hancock Stone Conecuh Monroe

Harrison Walthall Covington Perry

Jackson Wilkinson Dallas Washington

Lamar Escambia Wilcox

Geneva

Source: USDOI MMS (2005) and Fannin et al. (2011).

Table 35

Florida: 54 Counties that can be included in the Gulf Coast Economic Impact Area

Alachua DeSoto Hernando Liberty Putnam

Baker Dixie Highlands Madison Santa Rosa

Bay Escambia Hillsborough Manatee Sarasota

Bradford Franklin Holmes Marion Sumter

Broward Gasden Jackson Miami-Dade Suwannee

Calhoun Gilchrist Jefferson Monroe Taylor

Charlotte Glades Lafayette Okaloosa Union

Citrus Gulf Lake Palm Beach Wakulla

Clay Hamilton Lee Pasco Walton

Collier Hardee Leon Pinellas Washington

Columbia Hendry Levy Polk

Source: ERG estimates
46 

5.2 TOP-DOWN APPROACH

A goal of developing an onshore distribution of expenditures in the offshore GOM is to be 

able to evaluate the jobs, output, and other economic measures that reflect the local and regional 

spending patterns (as reflected in IMPLAN multipliers). To evaluate the effects of those 

expenditures, we need to estimate the portion of spending that occurs within the region for each 

IMPLAN sector. The end product to be used in MAG-PLAN is a 440-industry by 196-region19

ERG created IMPLAN models for the nation; five-state GOM; and individual states of

Texas, Louisiana, Mississippi, Alabama, Florida; plus an additional five models where each one 

contains the counties or parishes within a state that are in the Gulf coast economic impact area

(that is, the counties and parishes listed in Tables 32 through 35). In the top-down approach, we 

start with the largest region (World) and make a series of RS comparisons with increasingly 

smaller regions until we reach the state subregions shown in green in Figures 4 a nd 5, which

contain the 189 counties and parishes listed in Tables 32 through 35. Table 36 summarizes the 

regions and comparisons. 

matrix where the rows are the industries, the columns are the region, and cell content represents 

the percentage of expenditures that occur in that region for that industry. (Note that each row 

sums to 100 percent.) 

5.2.1 The Rest of World

Returning to Figures 2 and 5, the outermost circle is the dividing line between the proportion 

of national demand addressed by domestic production and that supplied by imports from the 

ROW. The portion of spending per industry that leaves the United States is calculated as: 

ROW onshore distributioni = 1 – U.S. National RSi

 Where:

RS = Regional share based on the regional purchase coefficient

 i = IMPLAN industry sectory 

That is, what the United States does not produce for itself is what the ROW supplies. 

 

19 Comprised of 189 counties or parishes, 5 Rest of State, 1 Rest of US, and 1 Rest of World.
47 

Table 36

Overview of Top-Down Approach

Region 1 Region 2 Compare to Estimate Described in 

Section

World U.S. Rest of World 5.2.1

U.S. Five-State GOM Rest of United States 5.2.2

Five-State 

GOM

TX, LA, MS, AL, FL Partition the five-state GOM region among 

the five individual states 

5.2.3

TX TX-GOM Partition each state into “GOM” and “Rest 

of State” regions

5.2.4

LA LA-GOM

MS MS-GOM

AL AL-GOM

FL FL-GOM

Partition each state “GOM” region into 

individual counties and parishes

5.2.5

5.2.2 Rest of United States

The difference between the percentage of demand supplied internally by the five-state GOM 

region and the percentage that must be supplied by the rest of the nation is represented by the 

area between the outer and middle circles (In Figures 3 and 5, see the double-headed arrow 

pointing right in the light gray area). The proportion of spending per industry that leaves the fivestate GOM region but stays within the United States is calculated as:

Rest of U.S. onshore distributioni = U.S. National RSi – Five-state GOM region RSi Where:

RS = Regional share based on the regional purchase coefficient

 i = IMPLAN industry sector 

5.2.3 Texas, Louisiana, Mississippi, Alabama, and Florida

In Figures 4 and 5, the reader will notice that the area within the middle circle (i.e., light gray 

and green) is subdivided into states by the dotted lines. At this point, we need to divide the fivestate GOM region into individual states. As mentioned at the beginning of the chapter, an 

IMPLAN model does not tell you the portion of demand in a larger region (e.g., five-state GOM) 

that is supplied by a smaller subregion (e.g., Texas). Furthermore, we cannot simply assign onefifth of the five-state GOM RS to each state because each state will have its own pattern of being 

able to supply its own demand for each industry. This pattern has as its basis the relative level of 

production for a specific industry in each state (that is, for a particular industry, some states 

produce more of a commodity than others and thus, can contribute a greater supply to the larger 

region). Therefore, we need a method for distributing supply that reflects what each state could 

contribute to the local production in the five-state GOM region in each industry sector. 

ERG uses coal as an example of how this relationship is estimated by combining the 

information within each state’s RS and that of the larger five-state GOM region (the gray plus 

green areas in Figure 5). In the example, the five-state GOM region RS for coal is 27.19 percent; 

that is, for every 100 u nits of coal demanded, 27.19 units are internally supplied by the five 
48 

states. Table 37 illustrates the calculations for allocating the 27.19 units among the five states. 

The first line uses each state’s RS to represent the number of units supplied within the state for 

every 100 units demanded with the state. In the example, Texas has an RS of 11.47 percent for 

coal. For every 100 uni ts of coal demanded in Texas, then, 11.47 uni ts are supplied locally. 

Alabama has an RS of 46.91 percent for coal, while Florida has an RS of less than 1 percent for 

coal. That is, the range of the proportion of coal supplied to meet local demand reflects the 

differing resource bases for coal among this group of states. The five-state sum is 70.28 units 

supplied locally within the five-state region. This number of units, though, cannot be compared 

to demand. A percentage comparing this supply (70.28 units) to the amount demanded cannot be 

directly calculated using this number, which, by itself, is meaningless. It can, however, be used 

to provide a sense of the underlying ability of each state to meet the overall demand of the fivestate region. 

The second line in Table 37 addresses the question, “Of all the coal supplied in the five-state 

region, what proportion is supplied by each state?” Alabama, for example, produces 46.91 units 

of every 70.28 units of coal (or 66.75 percent of the 70.28 coal units supplied within the fivestate region). Finally, the third line answers the question, “How can we assign a number of units 

supplied by each state per 100 units demanded within the five-state region such that the sum of 

those units will match the 27.19 uni ts supplied with the five-state region?” The table, now 

reporting percentages rather than units in the third line, reflects a weighted average RS for each 

of the states, which is obtained by multiplying the percentage of supply provided by a state 

shown in the second line by the five-state RS (27.19 percent). For Alabama, then, the state’s 

share is 27.19 uni ts (or percent) times 66.75 percent, which yields a w eighted RS of 18.15

percent. In this way, the sum of the individual state RPs is set equal to 27.19 percent (i.e., the 

five-state RP)—the amount of demand supplied by internal sources—but each state’s portion 

now reflects what that state could contribute to the supply, given its coal resources.

Table 37

Sample Calculation to Apportion Five-State RS among Five States

TX LA MS AL FL Sum

Units Supplied Locally 11.47 6.90 4.05 46.91 0.94 70.28

Proportion for Each State 16.33% 9.82% 5.76% 66.75% 1.34% 100%

Allocate Five-State GOM Region RS to Each State 4.44% 2.67% 1.57% 18.15% 0.36% 27.19%

Source: ERG estimates derived from IMPLAN data.

5.2.4 Separating Each State Into “GOM” and “Rest of” Regions

For each state, ERG developed separate IMPLAN models for the counties or parishes within 

the “GOM” region or “Gulf coast economic impact area” of that state (the green areas in Figures 

4 and 5) and the “Rest of” that state. In Figures 4 a nd 5, the “Rest of” state regions are

represented by the light gray area that lies between the green and dark gray areas, shown by the 

double-headed arrow pointing to the left of center. 

To estimate the portion of spending that occurs in the “Rest of” state regions, ERG examined 

the ratio of the GOM RS in a state to the RS for each state. That is, the numerator is the RS for a 

GOM subset of counties (or parishes) in the state, while the denominator is the RS for entire 

state. For example, the RS for coal in Louisiana is 6.9 percent (see first line of Table 37) while 
49 

the RS for the 40-parish Louisiana Gulf Coast Economic Impact Area is 0.59 percent (not 

shown). That is, the Louisiana Gulf Coast EIA’s RS is 8.57 percent of the state’s RS (0.59/6.9). 

The onshore distribution for coal in the 40-parish LA Gulf Coast EIA is then calculated as the 

product of the adjusted state RS (for Louisiana, this is the 2.67 percent from Table 37 line 3) and 

the ratio of the Gulf Coast EIA RS in a state to that state’s RS (for Louisiana, this is the 8.57

percent calculated above). In the example of Louisiana, the calculation is thus 2.67 percent times 

8.57 percent or 0.23 percent. To represent the Rest of Louisiana, the 0.23 percent is subtracted 

from 2.67 percent, producing an estimated RS for the Rest of Louisiana of 2.44 percent.

5.2.5 Separating State GOM Regions into Individual Counties or Parishes

In the example above, the 40-county region in Louisiana supplies 0.23 percent of the coal 

demanded. ERG divides the state Gulf Coast EIA region portion equally among all counties or 

parishes within the state. For example, each Louisiana parish in the Gulf Coast EIA region is 

assigned 1/40 of the 0.23 percent. This is because we do not know 1) where the money will go 

within this region and 2) how the individual counties will be grouped into economic regions for 

the analysis.

5.2.6 Observations

The first observation is that specific industries, such as G&G prospecting, might be 

concentrated in a f ew areas, such as Houston, rather than being equally distributed within the 

state coastal EIA regions. Section 5.3 describes how the onshore distribution of specific industry 

sectors important to offshore oil and gas operations are tailored to that industry. However, for the 

400+ of the 440 IMPLAN sectors of lesser importance to offshore oil and gas operations, the 

methodology provides a consistent approach for estimating the onshore distributions of these 

expenditures. 

The second observation is that the approach differs from that in the previous model 

documentation (USDOI MMS 2005).20 The 2005 report examined Census data in County 

Business Pattern (CBP) and considered there to be an inconsistency when CBP data showed only 

one establishment while IMPLAN showed a high RS for the same sector. In these cases, the 

earlier report modified the onshore distribution if another sector within the same three-digit 

NAICS code was similar enough to substitute for the original data. The difficulty with this 

approach is that the CBP data are not inconsistent. It is possible that a single large facility could 

produce enough of a commodity or service to fill a large portion of the regional demand. 

Therefore, we believe the approaches outlined in Sections 5.2 and 5.3 will produce a more 

accurate estimate of RPs compared to the previous version. 

 

20 Page 32 implies that “Other US” includes both “Other US” as defined here plus the ROW.
50 

5.3 INDUSTRY-SPECIFIC ONSHORE DISTRIBUTIONS

5.3.1 Oil Service Contract Industries

This section relies on Analysis of the Oil Services Contract Industry in the Gulf of Mexico 

Region (ERG 2011). The report examined 2007 data for 17 oil service industries21 and identified 

about 1,140 locations supporting about 63,000 employees and accounting for an estimated $19.3 

billion in revenues. Revenue and/or employment data was located for 76 percent of the locations. 

These data are the preliminary basis for developing onshore distributions for eight IMPLAN 

sectors (see Table 38). 

Table 38

Oil Service Industries and IMPLAN Sectors

IMPLAN Sector

Oil Service Industry Number Name

Contract Drilling 28 Drilling Oil and Gas Wells

Drilling Fluid

29 Support Activities for Oil and Gas Operations

Mud Logging

Measurement While Drilling

Cementing 

Formation Evaluation

Workover

Completion

Diving

Fishing

Drilling Tools 

Wellhead Equipment 206 Oil and Gas Field Equipment and Machinery

Air Transportation 332 Air Transportation

Water Transportation 334 Water Transportation

Geological and Geophysical Prospecting 369 Architectural and Engineering Services

Accommodations 412 Other Accommodations

Food Services 413 Food Services

Source: ERG (2011).

As mentioned earlier, approximately 24 percent of the locations did not have revenue or 

employment information. ERG imputed revenues for these locations by several methods: 

• Where we had company revenues and the number of locations, we used the average 

revenue for each location. Petroleum Helicopters, Inc. (PHI), for example, does not list 

revenues for any of its 12 locations, but ERG could find revenues for the entire company. 

Thus, we assigned 1/12 of the revenues to each location. 

 

21 Geological and geophysical prospecting, contract drilling, drilling fluid supplies, drilling tools and supplies, 

mud logging, measurement while drilling (MWD), cementing, formation evaluation, completion, fishing, wellhead 

equipment suppliers, accommodations, air transport, water transport, catering, workovers, and diving support.
51 

• Where we had company revenues and revenues for some (but not all) locations, ERG 

calculated the difference between total company revenues and the sum of location 

revenues and then divided the difference equally among the locations that lacked revenue 

data.

• Where we had the number of employees at a location but not the associated revenues, 

ERG calculated the average revenues per employee for that sector and multiplied it by the 

number of employees. 

• Where we lacked both employee and revenue data for a single-location company, we 

used the average revenue per location for that sector.

Although a small amount of uncertainty is introduced by imputing missing data, the 

alternative would be to allocate nothing to a county or parish where we know there is economic 

activity in that sector within that region.22

For the eight IMPLAN sectors shown in Table 38, we assumed that all demand from offshore 

oil and gas operations would be filled from within the five-state region. Thus, the onshore 

allocations for the ROW and the Rest of the United States are set to 0 percent. 

For some sectors, ERG (2011) identified locations that provided these services that are 

outside of the local economic region; these are assigned to the Rest of Texas, Rest of Louisiana, 

Rest of Mississippi, Rest of Alabama, and Rest of Florida regions, as appropriate. 

The onshore distribution is calculated by county/parish according to the location revenues 

within the county or parish. For IMPLAN sector 29 (support activities for oil and gas 

operations), ERG aggregated the data as shown in Table 38. For IMPLAN Sector 206 (oil and 

gas field equipment and machinery), ERG needed to extend the analysis to address additional 

industries such as platform fabrication, subseabed completion equipment manufacturers, and 

insurance. The analysis is discussed in the next section.

5.3.2 New Industries

For this project, ERG developed onshore distributions for platform fabrication, materials 

associated with subseabed completions, FPSOs, and insurance. Each is discussed in its own 

section below. 

5.3.2.1 Platform Fabrication

In 2009, the platform fabrication industry in the GOM supported more than 23,000 jobs and 

represented approximately $3.7 bi llion in gross revenues. Appendix D contains the data and 

methodology used to estimate the GOM onshore distribution for this industry sector. Fixed 

platforms tend to be made in the GOM. Hulls for semisubmersible platforms, however, tend to 

be made outside of the United States. Hull costs are approximately 7.5 percent of the 

semisubmersible costs (see Appendix E). For the purpose of not overestimating the contributions 

of industry expenditures in the GOM to the adjacent regions, ERG set the ROW to 7.5 percent 

 

22 The imputation of missing data also means that the onshore allocations will differ slightly from the summary 

tables in ERG (2011). 
52 

and decreased the contributions to the GOM parishes and counties proportionately (see Table 

39).23

Table 39

Onshore Distribution for the Platform Fabrication Activity

 The onshore distribution is assigned to IMPLAN Sector 290 (shipbuilding and repairing). 

State County/Parish

Revenue

(Millions) Percent

Adjusted 

Percent

AL Mobile $35.16 0.94% 0.87%

LA Iberia $433.75 11.63% 10.76%

LA Jefferson (LA) $41.16 1.10% 1.02%

LA Lafayette $9.40 0.25% 0.23%

LA Lafourche $0.60 0.02% 0.01%

LA Plaquemines $67.13 1.80% 1.66%

LA Saint Mary $131.85 3.54% 3.27%

LA Terrebonne $387.43 10.39% 9.61%

LA Vermilion $32.05 0.86% 0.79%

MS Jackson $398.00 10.67% 9.87%

MS Warren $249.06 6.68% 6.18%

TX Brazoria $5.24 0.140% 0.130%

TX Cameron (TX) $270.50 7.25% 6.71%

TX Galveston $4.50 0.12% 0.11%

TX Harris $298.42 8.00% 7.40%

TX Jefferson (TX) $19.88 0.53% 0.49%

TX Nueces $420.62 11.28% 10.43%

TX Orange $29.30 0.79% 0.73%

TX San Patricio $895.54 24.01% 22.21%

ROW 7.50%

Source: Appendix E.

5.3.2.2 Subsea Completions

Subsea systems have one or more subsea wells, manifolds, control umbilicals, 

pumping/processing equipment, or flow lines (USDOI MMS 2008). Five companies dominate 

the subsea production equipment market: Aker Solutions, Cameron International, Dril-Quip, 

FMC, and Vetco Gray (General Electric Oil and Gas) (Kopits and Jones 2010). During 2007–

2009, FMC held about 45 to 47 percent of the market, Cameron and Vetco Gray held about 17 to 

16 percent each, Aker Solutions garnered 13 percent, and Dril-Quip held the remaining 7 percent

(Kopits and Jones 2010). 

Aker is reported to have held 65 percent of the global steel tube umbilical market in 2008. 

The company has an umbilical manufacturing plant in Mobile, Alabama, where 90 percent of the 

workforce is from Mobile and the surrounding area (Alabama 2008). Umbilicals for the GOM 

are likely to originate at this plant and other regional facilities.

Cameron International has subsea manufacturing facilities in Berwick, Louisiana, as well as 

Leeds, England, and Johor, Malaysia (Cameron 2009). FMC lists production facilities for its 

 

23 The datasets supporting MAG-PLAN V2 indicate that the 2005 model has an onshore allocation of 91 percent 

of expenditures in the shipbuilding and repairing sector going to the “Other U.S.” region. While there are major 

shipbuilding yards on the East and West Coasts, they do not manufacture offshore oil and gas platforms.
53 

Energy Production Systems segment in Houston, Texas, and Oklahoma City, Oklahoma, and 

subsea systems accounted for 62 to 70 percent of FMC’s total revenues for 2007–2009. FMC has 

16 other manufacturing locations spread around the globe (FMC 2009). GE entered the oil and 

gas market with its acquisition of VetcoGray in 2007. VetcoGray’s manufacturing facility 

remains in Houston, Texas (GE 2008), and GE also lists a manufacturing operation in Harvey,

Louisiana (GE 2010). Dril-Quip has two manufacturing locations in Houston, Texas (Dril-Quip 

2009). 

ERG searched the D&B database (D&B 2010) for revenues associated with each of the 

locations (see Table 40). We integrated the information in Table 40 with the data for drilling 

tools and wellhead equipment in ERG (2011) to develop the onshore distribution for IMPLAN 

Sector 206 (mining and oil and gas field equipment and machinery).24,25 That is, the revenues and 

locations shown in Table 40 were added to those in ERG (2011), and the percentage of total 

revenues per county and parish were recalculated. 

Table 40

Subsea Equipment Manufacturers

Name Owner City State County

2009 

Revenues 

(Millions) Percent

Aker Subsea Mobile AL Mobile $75.0 16.29%

Energy Production Systems FMC Houston TX Harris $7.4 1.61%

Energy Production Systems FMC Oklahoma City OK Oklahoma $1.5 0.33%

Vetco Gray GE Houston TX Harris $148.3 32.21%

Vetco Gray GE Harvey LA Jefferson $12.7 2.76%

Dril-Quip Houston TX Harris $186.0 40.40%

Cameron International Berwick LA St. Mary $29.5 6.40%

Total $460.4 100.00%

Source: ERG estimates

ERG incorporated the findings of the June 2011 report by Quest Offshore Resources that 

indicated approximately 23% of oil and gas field equipment and machinery is manufactured 

outside of the GOM region (Quest Offshore Resources 2011). Table 41 presents the onshore 

distribution for IMPLAN Sector 206. 

 

24 During the integration, we identified that the Vetco Gray facility in Harvey, Louisiana, shown in Table 40 had 

already been captured in the wellhead equipment category in ERG (2011).

25 At this time, MAG-PLAN does not support multiple onshore distributions for a s ingle IMPLAN sector 

depending on the activity.
54 

5.3.2.3 FPSOs

The FPSO Activity Function is modeled as the vessel and associated subsea completion(s). 

Appendix C documents the data for an estimated vessel cost of $1.9 billion and a subsea 

completion cost of $200 million for a total cost of $2.1 billion. Thus, 9.52 percent of the activity 

cost ($200 million/$2.1 billion) is allocated to IMPLAN Sector 206 (mining and oil and gas field 

machinery) while the remaining 90.48 percent of the activity cost is allocated to IMPLAN Sector 

290 (shipbuilding and repairing). 

5.3.2.4 Insurance

Cost data for deep offshore wells collected by USDOE’s NETL indicates that insurance costs 

might represent as much as 11.9 percent of exploratory well costs but only 1.3 percent of 

development well costs (USDOE NETL 2005; ERG 2011). ERG examined the offshore 

insurance market to understand the onshore distribution of nearly 12 percent of exploratory well 

costs.

Dismukes and Peters (2011) provide an excellent overview of the types of offshore energy 

insurance in the course of examining the post-2004 changes in these insurance markets. These 

include, but are not limited to, self-insurance, mutualization, private insurance, and reinsurance. 

In self-insurance, an oil and gas company sets up an account to pay for losses from unforeseen 

events. Self-insurance is possible for major oil companies, particularly those whose assets exceed 

those of most insurance companies. In effect, the company pays the premiums to itself rather 

than to an insurance company. Mutualization describes the process of a group of companies 

organizing a joint pool that insures each member against different types of adverse incomes. Oil 

Insurance Limited (OIL) is the premier example of a mutual insurance company. One 

requirement for membership, however, is at least $1 billion in gross assets, and so, like selfinsurance, it is limited to large companies. Private insurance is commercial insurance. Lloyd’s of 

London is an insurance exchange where insurers and brokers can meet (much like a stock 

exchange). Reinsurers insure the insurance companies. This secondary market helps to diversify 

the risk of the primary insurance companies. Most companies use a mix of insurance types to 

meet their needs.
55 

Table 41

Onshore Distribution for IMPLAN Sector 206—Oil And Gas Field Equipment And Machinery

State County/Parish Percent

AL Mobile 1.14%

LA Ascension 0.00%

LA Calcasieu 0.58%

LA Cameron 0.01%

LA Iberia 2.24%

LA Jefferson 1.00%

LA Lafayette 6.52%

LA Lafourche 0.18%

LA Orleans 1.31%

LA Plaquemines 1.21%

LA St. Landry 0.08%

LA St. Martin 0.64%

LA St. Mary 1.20%

LA St. Tammany 0.30%

LA Terrebonne 2.23%

LA Vermilion 0.03%

TX Brazoria 0.17%

TX Cameron 0.01%

TX Fort Bend 1.09%

TX Harris 48.73%

TX Hidalgo 0.29%

TX Jefferson 0.03%

TX Jim Wells 0.94%

TX Montgomery 3.01%

TX Nueces 0.89%

TX San Patricio 0.04%

TX Victoria 0.49%

TX Waller 0.63%

TX Wharton 0.04%

LA Rest of LA 1.15%

TX Rest of TX 0.83%

Rest of US 23.00%

Sum 100.00%

Source: ERG estimates based on ERG (2011) and 

Table 40.
56 

Dismukes and Peters (2011) summarizes the share of losses borne by self-insurers; OIL; and 

the commercial market from Hurricanes Ivan, Katrina, Rita, and Ike (see Table 42). If we assume 

that the insurance patterns for the assets damaged or destroyed by the hurricanes are typical of 

the insurance patterns for the GOM, self-insurers (industry) absorbed from 3 to 46 percent of the 

losses, OIL absorbed between 10 and 30 percent of the losses, and commercial insurers absorbed 

between 42 and 67 percent of the losses. 

On a combined basis, about one-third of the insurance coverage is provided by the oil and 

gas companies themselves. In 2009, Willis Group Holdings noted that a smaller exploration and 

production company might find it more advantageous to self-insure given premium and loss 

limits (Willis Group Holdings 2009). As reported in Rigzone, a 2010 study by IHS Global 

Insight noted that independents are the largest shareholder in 66 percent of the 7,521 leases in the 

entire Gulf and in 81 percent of producing leases (Rigzone 2010). Thus, we might infer that 

between 22 and 28 percent of the insurance coverage is self-insurance by independent oil and gas 

companies. ERG also infers that this expenditure is likely to stay within the United States, while 

self-insurance expenditures by major firms with multinational interests are likely to go outside 

the United States. ERG uses the mid-point of the range (25 percent) for the onshore allocation to 

remain in the United States.

Table 42

Gulf of Mexico Insurance and Hurricane Losses

 Hurricane 

Metric Ivan Katrina Rita Ike Combined

Total Loss (Millions, current) $1,859 $7,078 $5,557 $5,949 $20,443

Estimated Losses (Millions) Borne by:

Industry $49 $3,268 $1,257 $2,349 $6,923

OIL $560 $810 $800 $600 $2,770

Commercial Market $1,250 $3,000 $3,500 $3,000 $10,750

Share of Losses Borne by:

Industry 3% 46% 23% 39% 34%

OIL 30% 11% 14% 10% 14%

Commercial Market 67% 42% 63% 50% 53%

 Source: Dismukes and Peters (2011) 
57 

This means that the sum of the insurance expenditures associated with the commercial 

market (53 percent), OIL (14 percent), and self-insurance by major oil companies (8 percent), or 

75 percent of the expenditures associated with NAICS 5241 (IMPLAN industry 357, insurance 

carriers), is very likely to go outside of the United States.26

Although it is more likely that the remaining 25 percent of spending in IMPLAN industry 

357 would remain within the five-state GOM region rather than going elsewhere within the 

United States, ERG could not locate information to support a more detailed distribution of the 

spending. As a result, ERG assigned the 25 percent to the Rest of the United States. 

Finally, ERG examined oil and gas insurance companies as listed in the 2008 Gulf Coast Oil 

Directory. ERG removed companies that insured only vessels and those that insured only 

onshore operations and found 29 companies that indicated they provided coverage for offshore 

oil and gas operations. All of these companies fall under NAICS 5242 (IMPLAN industry 358, 

insurance agents). Unfortunately, many of the largest companies (e.g., Texas Mutual Insurance 

Company) have substantial activities in other areas as well. ERG examined the RPs for this 

industry and found that they were very high in each county/parish. Thus, insurance costs are 

likely to be internally supplied wherever the expenditure is made. As a result, ERG did not 

pursue a geographic refinement of this industry but remained with the distribution as calculated 

with the Section 5.2 methodology. 

5.4 ONSHORE DISTRIBUTIONS FOR LABOR

MAG-PLAN divides expenditures in to non-labor and labor spending (see Chapter 2.0). As 

seen in the previous sections, MAG-PLAN uses a sector-by-onshore-area matrix to distribute the 

spending to onshore areas. In contrast, MAG-PLAN uses an activity function-by-onshore-area 

matrix for the labor onshore distribution. For all but four Activity functions, 27

The four exceptions are the three drilling activity functions and the production function.

Offshore oil and gas work schedules, particularly for those in operations on offshore production 

structures, frequently take a “multiweek period on/multiweek period off” format. Thus, offshore 

oil and gas workers have the flexibility to live substantial distances away from the GOM region. 

This phenomenon was investigated by the Labor Needs Survey, which developed a distribution 

of the percent of the labor force by home ZIP code (ICF 2008, he reafter called “LNS”). To 

protect the confidentiality of workers’ home addresses, ICF aggregated data by 1-, 2-, or 3-digit 

ZIP codes as well as by state and multistate areas. For use in MAG-PLAN, however, the onshore 

distribution for labor in four Activity Functions needs to be distributed among counties and 

parishes.

workers are 

assumed to live within commuting distance of their work place. 

Table 43 is a copy of the ZIP code, area, and percentage data from the LNS. LNS does not 

provide a finer breakdown of the data and ZIP code boundaries do not necessarily correspond to 

county or parish boundaries. Table 44 is the list of the LNS ZIP code areas that correspond to a 

single county or MAG-PLAN region. ZIP code 770 lies entirely within Harris County, TX. The 

 

26 Dismukes and Peters (2011) note that Watkins Syndicate is the largest direct insurer in the GOM. Watkins 

Syndicate and Munich Reinsurance (the world’s largest reinsurer) are foreign companies, as is the Lloyd’s 

exchange.

27Drilling (exploratory, non-productive development, and productive development wells) and production 

operations and maintenance.
58 

other ZIP codes in Harris County, TX are discussed further below. No further adjustment needs 

to be made to the Table 44 data for use in MAG-PLAN.

For the other two- and three-digit ZIP code regions, ERG began by visually overlaying the 

ZIP code map on t he state map of counties/parishes (GoToMyList.com 2012; U.S. Census 

Bureau 2012a). ERG noted which counties/parishes fell completely within the ZIP code and 

those which were only partially within a ZIP code. For all counties/parishes within a ZIP code, 

ERG downloaded 2010 labor force data from American Factfinder (U.S. Census Bureau, 2012). 

The entire labor force was counted for counties/parishes that lay entirely within the ZIP code. 

One-half of the labor force was counted for counties/parishes that lay partly in the ZIP code. The 

exception is Harris County, Texas. ZIP code 770 lies entirely within Harris County and is 

assumed to represent 70% of the labor force. Harris County also includes parts of ZIP codes 773, 

774, and 775. ERG assigned 10% of the Harris County labor force to each of these ZIP codes. 

Table 43 

Onshore Distribution for Labor in Offshore Oil and Gas Operations

ZIP Code Area Percent

32 Northern Florida 1.94%

36 Mobile, Montgomery, AL 3.33%

39 Biloxi, Jackson, Southern MS 4.28%

Arkansas & Tennessee 0.82%

700 Metairie, Chalmette, LA 3.67%

701 New Orleans, LA 0.66%

703 Houma, Donaldsonville, LA 20.78%

704 Hammond, Ponchatoula, Bogalusa, LA 4.62%

705 Lafayette, New Iberia, Abbeville, LA 18.75%

706 Lake Charles, LA 1.40%

Other South LA 0.58%

71 Shreveport, LA 4.01%

75-76 Dallas & Forth Worth 0.89%

770 Houston, TX 9.81%

773 Humble, Kingwood, Spring, TX 9.14%

774 Katy, Park Row, Sugarland, TX 1.20%

775 Deer Park, Galveston, Pearland, TX 5.23%

Other Coastal TX 0.69%

78 Austin, Corpus Christi, San Antonio, TX 6.46%

9 West Coast 0.79%

Other Lower 48 0.94%

Sum 99.99%

Source: ICF 2008, Table 5.4
59 

Table 44 

Labor Onshore Distribution: No Adjustments

ZIP Code Area Percent MAG-PLAN Region

Arkansas & Tennessee 0.82% Rest of US

Other South LA 0.58% Rest of LA

71 Shreveport, LA 4.01% Rest of LA

75-76 Dallas & Forth Worth 0.89% Rest of TX

770 Houston, TX 9.81% Harris

Other Coastal TX 0.69% Rest of TX

78

Austin, Corpus Christi, San Antonio, 

TX 6.46% Rest of TX

9 West Coast 0.79% Rest of US

Other Lower 48 0.94% Rest of US

Source: ICF 2008, Table 5.4 

The approach is illustrated for Texas in Table 45. The columns labeled “Weights” is the 

fraction of the labor force in the ZIP code region that falls within a county. For example, in ZIP 

code 773, the regional employment is the sum of employment of Montgomery, Walker, and Polk 

Counties (254,998), half the employment in Liberty County (16,052), and one-tenth the 

employment in Harris County (203,867). That is, the labor force in ZIP code 773 is an estimated 

474,917. Montgomery County, with its labor force of 215,426 accounts for 45.4% of the ZIP 

code labor force.

The next column, “LNS Percent,” is the fraction of the offshore workforce in that ZIP code 

(see Table 43). The LNS percent is multiplied by the weight to calculate the “Allocated Percent.” 

For Montgomery County, the calculation is 45.4% times 9.14% or 4.15%. 

Because several counties are located in more than one ZIP code region, the allocated percents 

must be summed back to county totals (rightmost columns). For example, the 1.11% for Brazoria 

County reflects the 0.14% from ZIP code 774 plus 0.97% from ZIP Code 775. The labor 

percentage for Harris County reflects the sum of 9.81% from ZIP code 770 (see Table 44), 

3.92% from ZIP code 773, 0.39% from ZIP code 774, and 2.70% from ZIP code 775. 

Table 46 shows the same calculations for Louisiana. 
60 

Table 45

Texas Onshore Labor Distribution

Allocation Summary

ZIP code County All/Part

Total County

Labor Force Weights

LNS 

Percent

Allocated 

Percent County Percent

773

Montgomery All 215,426 45.4%

9.14%

4.15% Austin 0.01%

Walker All 22,671 4.8% 0.44% Brazoria 1.11%

Polk All 16,901 3.6% 0.33% Chambers 0.21%

Liberty Part 32,104 3.4% 0.31% Colorado 0.01%

Harris Part 2,038,674 42.9% 3.92% Fort Bend 0.53%

774

Waller All 20,404 3.29%

1.20%

0.04% Galveston 0.97%

Fort Bend All 273,604 44.05% 0.53% Hardin 0.17%

Wharton All 20,542 3.31% 0.04% Harris 16.82%

Matagorda All 17,282 2.78% 0.03% Liberty 0.52%

Brazoria Part 147,009 11.83% 0.14% Matagorda 0.03%

Colorado Part 9,497 0.76% 0.01% Montgomery 4.15%

Austin Part 14,272 1.15% 0.01% Polk 0.33%

Harris Part 2,038,674 32.82% 0.39% Walker 0.44%

775

Chambers All 15,815 4.00%

5.23%

0.21% Waller 0.04%

Liberty Part 32,104 4.06% 0.21% Wharton 0.04%

Hardin Part 25,103 3.17% 0.17%

Galveston Part 147,417 18.64% 0.97%

Brazoria Part 147,009 18.59% 0.97%

Harris Part 2,038,674 51.55% 2.70%

Source: ERG estimates based on GoToMyList.com (2012); U.S. Census Bureau (2012a); and ; U.S. Census Bureau 

(2012b).
61 

Table 46

Louisiana Onshore Labor Distribution

Allocation Summary

ZIP 

code Parish All/Part Total ParishLabor Force Weights LNS Percent

Allocated 

Percent Parish Percent

700

Plaquemines All 10,217 5.4%

3.67%

0.20% Acadia 1.85%

St. Bernard All 13,257 7.0% 0.26% Allen 0.05%

St. Charles All 26,601 14.0% 0.51% Ascension 3.68%

St. John the 

Baptist All 22,987 12.1% 0.44% Assumption 1.44%

Jefferson Part 224,767 59.0% 2.16% Beauregard 0.16%

St. James Part 10,285 2.7% 0.10% Calcasieu 0.98%

701

Orleans All 150,066 57.18%

0.66%

0.38% Cameron 0.04%

Jefferson Part 224,767 42.82% 0.28% Evangeline 0.45%

703

Assumption All 10,061 6.91%

20.78%

1.44% Iberia 2.33%

Lafourche All 44,628 30.66% 6.37% Jefferson 2.45%

Terrebonne All 52,181 35.84% 7.45%

Jefferson 

Davis 0.54%

Ascension Part 51,623 17.73% 3.68% Lafayette 7.90%

St. Mary Part 25,788 8.86% 1.84% Lafourche 6.37%

704

St. Helena All 4,891 2.23%

4.62%

0.10% Livingston 0.63%

St. Tammany All 110,796 50.54% 2.33% Orleans 0.38%

Tangipahoa All 55,125 25.14% 1.16% Plaquemines 0.20%

Washington All 18,601 8.48% 0.39% St. Bernard 0.26%

Livingston Part 59,642 13.60% 0.63% St. Charles 0.51%

705

Acadia All 26,888 10.02%

18.50%

1.85% St. Helena 0.10%

Iberia All 33,755 12.58% 2.33% St. James 0.10%

Lafayette All 114,566 42.69% 7.90%

St. John the 

Baptist 0.44%

St. Martin All 24,055 8.96% 1.66% St. Landry 1.18%

Vermilion All 25,806 9.62% 1.78% St. Martin 1.66%

Evangeline Part 13,039 2.43% 0.45% St. Mary 2.73%

Jefferson Davis Part 13,531 2.52% 0.47% St. Tammany 2.33%

St. Landry Part 34,245 6.38% 1.18% Tangipahoa 1.16%

St. Mary Part 25,788 4.80% 0.89% Terrebonne 7.45%

706

Beauregard All 15,123 11.48%

1.40%

0.16% Vermillion 0.00%

Calcasieu All 92,007 69.84% 0.98% Vernon 0.10%

Cameron All 3,632 2.76% 0.04% Washington 0.39%

Allen Part 9,527 3.62% 0.05%

Jefferson Davis Part 13,531 5.14% 0.07%

Vernon Part 18,879 7.17% 0.10%

Source: ERG estimates based on GoToMyList.com (2012); U.S. Census Bureau (2012a); and U.S. Census Bureau 

(2012b).

Tables 47 and 48 show the calculations for Mississippi (ZIP code 39) and Alabama (ZIP 

code 36), respectively. For these states, the two-digit ZIP codes cover a substantial portion of the 

state. Each county is flagged by whether or not it is in the “Rest of” state region. The percentages 

for the counties flagged as “Y” are summed to estimate the “Rest of” allocation. For Mississippi, 

the “Rest of MS” is 2.77% and, for Alabama, the “Rest of AL” is 1.74%. 
62 

Table 47

Mississippi Onshore Labor Distribution

Allocation

Rest of 

County All/Part MS

Total County

Labor Force Weights

LNS 

Percent

Allocated 

Percent

Adams All 13,810 1.5%

4.28%

0.06% Y

Amite All 5,060 0.5% 0.02% N

Attala All 8,473 0.9% 0.04% Y

Choctaw All 3,802 0.4% 0.02% Y

Claiborne All 4,000 0.4% 0.02% Y

Clarke All 7,207 0.8% 0.03% Y

Clay All 9,325 1.0% 0.04% Y

Copiah All 12,613 1.3% 0.06% Y

Covington All 8,494 0.9% 0.04% Y

Forrest All 36,505 3.8% 0.16% N

Franklin All 3,274 0.3% 0.01% Y

George All 9,218 1.0% 0.04% N

Greene All 4,482 0.5% 0.02% N

Hancock All 19,445 2.0% 0.09% N

Harrison All 93,578 9.8% 0.42% N

Hinds All 119,964 12.6% 0.54% Y

Holmes All 7,401 0.8% 0.03% Y

Humphreys All 3,756 0.4% 0.02% Y

Issaquena All 729 0.1% 0.00% Y

Jackson All 66,877 7.0% 0.30% N

Jasper All 7,466 0.8% 0.03% Y

Jefferson All 2,537 0.3% 0.01% Y

Jefferson Davis All 5,239 0.6% 0.02% Y

Jones All 29,027 3.1% 0.13% Y

Kemper All 3,809 0.4% 0.02% Y

Lamar All 26,654 2.8% 0.12% N

Lauderdale All 37,091 3.9% 0.17% Y

Lawrence All 5,437 0.6% 0.02% Y

Leake All 8,983 0.9% 0.04% Y

Lincoln All 14,801 1.6% 0.07% Y

Lowndes All 28,718 3.0% 0.13% Y

Madison All 47,110 5.0% 0.21% Y

Marion All 10,563 1.1% 0.05% N

Neshoba All 12,693 1.3% 0.06% Y

Newton All 9,550 1.0% 0.04% Y

Noxubee All 4,728 0.5% 0.02% Y

Oktibbeha All 22,935 2.4% 0.10% Y

Pearl River All 24,216 2.5% 0.11% N

Perry All 5,426 0.6% 0.02% N
63 

Table 47. 

Mississippi Onshore Labor Distribution (cont.)

 Allocation

Rest of 

County All/Part MS Total County

Labor Force Weights LNS 

Percent

Allocated 

Percent

Pike All 16,551 1.7%

4.28%

0.07% N

Rankin All 71,596 7.5% 0.32% Y

Scott All 12,813 1.3% 0.06% Y

Simpson All 12,609 1.3% 0.06% Y

Smith All 7,166 0.8% 0.03% Y

Stone All 7,306 0.8% 0.03% N

Warren All 23,877 2.5% 0.11% Y

Walthall All 5,954 0.6% 0.03% N

Wayne All 8,592 0.9% 0.04% Y

Webster All 4,451 0.5% 0.02% Y

Wilkinson All 3,485 0.4% 0.02% N

Winston All 8,669 0.9% 0.04% Y

Yazoo All 11,471 1.2% 0.05% Y

Monroe Part 16,859 0.9% 0.04% Y

Montgomery Part 4,741 0.2% 0.01% Y

Sharkey Part 2,149 0.1% 0.00% Y

Source: ERG estimates based on GoToMyList.com (2012); U.S. Census Bureau (2012a); and ; U.S. 

Census Bureau (2012b).
64 

Table 48

Alabama Onshore Labor Distribution

Allocation

Rest of 

County All/Part AL

Total County

Labor Force Weights

LNS 

Percent

Allocated 

Percent

Autauga All 26,635 2.8%

3.33%

0.09% Y

Baldwin All 84,253 8.8% 0.29% N

Barbour All 10,966 1.2% 0.04% Y

Bullock All 4,854 0.5% 0.02% Y

Butler All 8,994 0.9% 0.03% N

Calhoun All 50,958 5.4% 0.18% Y

Chambers All 15,951 1.7% 0.06% Y

Choctaw All 5,156 0.5% 0.02% N

Clarke All 9,072 1.0% 0.03% N

Clay All 6,461 0.7% 0.02% Y

Cleburne All 6,547 0.7% 0.02% Y

Coffee All 22,496 2.4% 0.08% Y

Conecuh All 5,091 0.5% 0.02% N

Covington All 17,305 1.8% 0.06% N

Crenshaw All 6,436 0.7% 0.02% Y

Dale All 24,275 2.5% 0.08% Y

Dallas All 18,168 1.9% 0.06% N

Elmore All 36,203 3.8% 0.13% Y

Escambia All 14,918 1.6% 0.05% N

Geneva All 12,125 1.3% 0.04% N

Henry All 8,033 0.8% 0.03% Y

Houston All 47,309 5.0% 0.17% N

Lee All 68,545 7.2% 0.24% Y

Lowndes All 4,915 0.5% 0.02% N

Macon All 9,308 1.0% 0.03% Y

Marengo All 8,482 0.9% 0.03% N

Mobile All 193,846 20.4% 0.68% N

Monroe All 9,731 1.0% 0.03% N

Montgomery All 112,883 11.9% 0.39% Y

Perry All 3,957 0.4% 0.01% N

Pike All 15,642 1.6% 0.05% Y

Randolph All 10,019 1.1% 0.04% Y

Russell All 24,141 2.5% 0.08% Y

Tallapoosa All 19,568 2.1% 0.07% Y

Washington All 7,209 0.8% 0.03% N

Wilcox All 3,232 0.3% 0.01% N

Chilton Part 20,222 1.1% 0.04% Y

Greene Part 3,692 0.2% 0.01% Y

Hale Part 7,007 0.4% 0.01% Y

Sumter Part 6,406 0.3% 0.01% Y

Source: ERG estimates based on GoToMyList.com (2012); U.S. Census Bureau (2012a); and ; U.S. Census 

Bureau (2012b).
65 

Table 49 shows the calculations for Florida. In this case, ZIP codes beginning with 

“32”extend across northern Florida and down the east coast of the state. ERG limited the 

counties in the analysis to those identified across northern Florida in the 2005 M AG-PLAN 

technical report. That is, counties along the East Coast of Florida are excluded. This is consistent 

with the findings in Fannin et al. (2011). 

Table 49

Florida Onshore Labor Distribution

Allocation

County All/Part Labor 

Force Weights LNS Percent

Allocated 

Percent

Alachua All 125,027 12.7%

3.33%

0.42%

Bay All 87,101 8.8% 0.29%

Bradford All 11,645 1.2% 0.04%

Calhoun All 4,933 0.5% 0.02%

Columbia All 29,640 3.0% 0.10%

Dixie All 5,757 0.6% 0.02%

Escambia All 150,620 15.3% 0.51%

Franklin All 5,277 0.5% 0.02%

Gadsden All 18,063 1.8% 0.06%

Gilchrist All 7,423 0.8% 0.03%

Gulf All 6,095 0.6% 0.02%

Hamilton All 5,121 0.5% 0.02%

Holmes All 7,405 0.8% 0.03%

Jackson All 18,293 1.9% 0.06%

Jefferson All 6,509 0.7% 0.02%

Lafayette All 3,726 0.4% 0.01%

Leon All 149,358 15.1% 0.50%

Liberty All 3,678 0.4% 0.01%

Madison All 8,230 0.8% 0.03%

Okaloosa All 98,337 10.0% 0.33%

Santa Rosa All 73,712 7.5% 0.25%

Suwannee All 17,441 1.8% 0.06%

Taylor All 10,007 1.0% 0.03%

Union All 5,441 0.6% 0.02%

Wakulla All 14,093 1.4% 0.05%

Walton All 25,386 2.6% 0.09%

Washington All 10,277 1.0% 0.03%

Levy Part 17,354 0.9% 0.03%

Marion Part 137,320 7.0% 0.23%

Source: ERG estimates based on GoToMyList.com (2012); U.S. Census Bureau (2012a); and ; 

U.S. Census Bureau (2012b).
66 

For some sectors, ERG assumed that people tended to live within a traditional commuting 

distance of where they worked. The distribution associated with specific activity functions is 

provided in Table 50. 

Table 50

Activity Functions, Sectors, and Onshore Distributions

Activity Function IMPLAN 

Sector Onshore Distribution based on

Exploratory Drilling Labor Needs Survey

Nonproductive Development 

Drilling

Labor Needs Survey

Development Drilling and 

Production

Labor Needs Survey

Geological & Geophysical 

Prospecting

369

Architectural, engineering, and related services

Platform Fabrication and Installation 209 Shipbuilding

FPSO

Subseabed 206 Mining and oil and gas field equipment

Onshore Gas Processing 

Construction

35 Construction of new non-residential 

manufacturing structures 

Offshore Pipeline Construction

Decommission Platform (explosives) 29 Support activities for oil and gas operations

Decommission Platform (no 

explosives)

Onshore Oil Spill 390 Waste management and remediation services

Offshore Oil Spill

Production Operations and 

Maintenance

28 Labor Needs Survey 

Onshore Gas Processing O&M

Offshore Pipeline O&M 

Source: ERG estimates
67 

5.5 MODIFYING THE ONSHORE DISTRIBUTIONS FOR WESTERN AND CENTRAL 

GOM AREAS

ERG developed additional onshore distributions for the western and central GOM areas28

under the following assumptions: 

• Assumption 1: Sectors that are likely to be provided by local vendors are retail and 

service sectors. These are IMPLAN sectors 320 and higher in the 440-industry scheme. 

• Assumption 2: Texas provides locally to the western GOM while Louisiana provides 

locally to the central GOM.

• Assumption 3: The onshore distributions for sectors for which detailed distributions were 

developed (Section 5.3) might or might not differ for the Western and Central GOM 

areas.

For IMPLAN sectors 320 and higher, ERG retained the values for the Rest of United States,

the ROW, and the Rest of State regions as developed in Section 5.2 (i.e., the distributions for the 

Rest of regions used for western and central GOM are the same as those used for GOM). We 

then summed these seven values (ROW and Rest of US, TX, LA, MS, AL, and FL). The 

difference between 100 percent and the aggregate sum is the onshore distribution within the 189 

counties and parishes in the GOM region (“GOM onshore distribution”). For the western GOM, 

the distributions for the counties and parishes in Louisiana, Mississippi, Alabama, and Florida 

were set to zero and the GOM onshore distribution was divided equally among the 63 T exas 

counties. For the central GOM, the distributions for the counties in Texas, Mississippi, Alabama, 

and Florida were set to zero and the GOM onshore distribution was divided equally among the 

40 Louisiana parishes.

For six sectors, detailed onshore distributions were not modified because they are unlikely to 

vary between operations in the Western and Central GOM regions: 

• Sector 28 (drilling oil and gas wells) 

• Sector 29 (support activities for oil and gas operations) 

• Sector 206 (mining and oil and gas field equipment and machinery

• Sector 290 (shipbuilding and repairing) 

• Sector 357 (insurance carriers) 

 

28 As with any modeling effort, there are always improvements and expansions to be made. Currently, we have

insufficient information to develop datasets for the Eastern GOM region. For initial efforts, logistical support might 

be brought from existing businesses in the Central, or possibly Western GOM region(s). At this time, we do not 

know the “tipping point”; that is, the sustained level of activity needed for new businesses to begin in the coastal 

EGOM region. The geographic distribution for the West and Central GOM regions was developed from existing 

data on actual businesses and locations. These data do not yet exist for all economic aspects in the Eastern GOM 

region. 
68 

• Sector 412 (other accommodations) 

Onshore distributions were modified for four sectors: 

• Sector 332 (air transportation)

• Sector 334 (water transportation)

• Sector 369 (architectural, engineering, and related services)

• Sector 413 (food services)

For Sectors 332, 334, and 413, the services are assumed to originate in either the Western 

GOM or Central GOM. For Western GOM, the onshore distribution percentages for the Texas 

counties and Rest of Texas are summed and each subregion’s share of the total Texas 

distribution is calculated. The Western GOM distribution is then based on these values (i.e., 100 

percent is divided among the named Texas counties, based on each county’s share of the total 

Texas counties’ distribution calculated above). For the Central GOM, the same method is used 

except only Louisiana parishes are included. 

The onshore distribution for Sector 369 (architectural, engineering, and related services) was 

not modified for the Central GOM because so much of these services originate in Texas. For the 

Western GOM, however, the small percentage (about 6%) of architectural, engineering, and 

related services distributed to Louisiana parishes in the Gulf-wide distribution is redistributed to 

Texas counties on the proportional basis described for Sectors 332, 334, and 413. 

6.0 R E VE NUE FUNCTIONS

As mentioned in Section 2.4, revenue functions are: 

• Bonus bids 

• Rental payments

• Royalties on oil and gas production 

These appear as six columns in an E&D scenario, where each revenue function is subdivided 

into 8(g) and non-8(g) categories.

29

Figure 6 illustrates the revenue function logic flow within MAG-PLAN. The top box is 

labeled “Bonus, Rent or Royalty” because each revenue type is processed in the same manner. 

The first step is to separate the revenue type into non-8(g) and 8(g) revenue activities. All non8(g) revenues go to the federal government. That is, 100 percent of the funds are assigned to the 

United States with the associated IMPLAN Sector 429 ( federal government enterprises other 

than electric utilities).

The right-hand part of Figure 6 concerns the 8(g) revenues. These funds are split between the 

federal government and the GOM states. As with the non-8(g) funds, the 73 percent of the 8(g) 

funds that go to the federal government are allocated to IMPLAN Sector 429. 

 

29 The royalty data provided in the E&D scenario incorporates all royalty relief categories (i.e., Deepwater, 

Shallow Water Deep Gas, End-of-Life, and Special Case) (USDOI BOEM 2011).
69 

The 27 percent of the 8(g) funds that go to the GOM states are divided among the states 

according to the state waters adjacent to the location of the site where the bonus, rent, or royalty 

was generated. The Office of Natural Resources Revenue provides total Federal offshore 

disbursements by state by year, including a line item for GOMESA funds. ERG subtracted the 

GOMESA funds from total disbursement to estimate the 8(g) funds disbursed to the state for that 

year. To estimate the percentages shown in Figure 6, ERG downloaded disbursement data by 

state for FY 2008–2010 from (USDOI ONRR 2011). After calculating the 8(g) funds for each 

state, ERG summed the entries to obtain the 5-state total for 8(g) funds and then calculated the 

percentage of total 8(g) funds dispersed to each state (see Table 45). The percentages shown in 

Figure 6 are the three-year averages (see Table 46). All state monies are allocated to IMPLAN 

Sector 432 (state and local government enterprises other than passenger transit or electric 

utilities).The Federal portion of 8(g) funds are also allocated to IMPLAN Sector 429. 
70 

Figure 6. Revenue function logic flow. 
71 

Table 51

8(g) Funds Disbursed by Fiscal Year and State

FY 2010

State Disbursed GOMESA 8(g) Percent

Texas $4,211,242 $243,045 $3,968,197 11.6%

Louisiana $23,305,187 $699,757 $22,605,430 66.2%

Mississippi $859,244 $589,825 $269,419 0.8%

Alabama $7,951,467 $651,166 $7,300,301 21.4%

Florida $1,489 $0 $1,489 0.0%

Total $36,328,629 $2,183,793 $34,144,836 100.0%

FY 2009

Disbursed GOMESA 8(g) Percent

Texas $8,289,335 $2,159,399 $6,129,936 16.2%

Louisiana $28,664,551 $6,347,321 $22,317,230 59.2%

Mississippi $5,957,620 $5,506,235 $451,385 1.2%

Alabama $15,008,729 $6,179,076 $8,829,653 23.4%

Florida $1,376 $0 $1,376 0.0%

Total $57,921,611 $20,192,031 $37,729,580 100.0%

FY 2008

Disbursed GOMESA 8(g) Percent

Texas $13,346,657 $0 $13,346,657 17.9%

Louisiana $45,763,396 $0 $45,763,396 61.3%

Mississippi $564,068 $0 $564,068 0.8%

Alabama $14,990,923 $0 $14,990,923 20.1%

Florida $83 $0 $83 0.0%

Total $74,665,127 $0 $74,665,127 100.0%

Source: USDOI ONRR 2011
72 

Table 52

Average 8(g) Funds Disbursed by State

FY2010 FY2009 FY2008 Average 8(g) Fraction

Texas 11.6% 16.2% 17.9% 15.2% 4.1%

Louisiana 66.2% 59.2% 61.3% 62.2% 16.8%

Mississippi 0.8% 1.2% 0.8% 0.9% 0.2%

Alabama 21.4% 23.4% 20.1% 21.6% 5.8%

Florida 0.0% 0.0% 0.0% 0.0% 0.0%

Total State 100.0% 100.0% 100.0% 100.0% 27.0%

Federal 73.0%

Total 8(g) 100.0%

Source: ERG estimates based on date in Table 51.
73 

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U.S. Department of the Interior, Bureau of Ocean Energy Management, Regulation, and 

Enforcement. 2010d. Summary file for detail list of all company file. Available at: 

http://www.gomr.BOEM.gov/homepg/pubinfo/freeasci/leasing/zipped/fixed/CompanyAllFix

eddfn.html. 

U.S. Department of the Interior. Bureau of Ocean Energy Management. 2011a. Royalty relief 

information. Available at: http://www.gomr.boemre.gov/homepg/offshore/royrelef.html. 

U.S. Department of the Interior. Bureau of Ocean Energy Management. Office of Resource 

Evaluation. 2011b. Email from Michael Barton (ORE) to Kristen Stellec dated February10, 

2011 transferring the low, medium, and high drilling cost estimates for exploratory and 

productive wells by well depth and water depth in attached spreadsheet named 

KristenStrellecRevisedPreliminaryWellCosts.xls.

U.S. Department of the Interior. Bureau of Ocean Energy Management. Office of Lease 

Evaluation. 2011c. Email from Kim Coffman (LE) to Maureen Kaplan, Eastern Research 

Group, Inc. dated February 11, 2011 transferring the historical data in TIMS on 4,846 wells 

(counts and percentages, by well depth and water depth, by exploratory or production, by 

Western and Central GOM) in attached spreadsheet named Well Cost WLD Avgs MAGPLAN GOM.xls.

U.S. Department of the Interior. Minerals Management Service. 2005. Upgrading the Outer 

Continental Shelf economic impact models for the Gulf of Mexico and Alaska MAG-PLAN: 

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

Region, New Orleans, LA. OCS Report MMS 2005-046. 

U.S. Department of the Interior. Minerals Management Service. 2006. Offshore minerals 

management. Alaska OCS region. Beaufort Sea exploration wells. Available at: 

http://www.mms.gov/alaska/fo/wellhistory/BS_WELLS.HTM; 

http://www.mms.gov/alaska/fo/wellhistory/ALLWELLC.HTM. 
78 

U.S. Department of the Interior. Minerals Management Service. 2008. Deepwater Gulf of 

Mexico 2008: America’s offshore energy future. OCS Report MMS 2008-013. May. 

Available at: http://www.gomr.boemre.gov/PDFs/2008/2008-013.pdf.

U.S. Department of the Interior. Minerals Management Service. 2009. Deepwater Gulf of 

Mexico 2009: Interim report of 2008 highlights. OCS Report MMS 2009-016. May. 

Available at: http://www.gomr.boemre.gov/PDFs/2009/2009-016.pdf. 

U.S. Department of the Interior. Office of Natural Resources Revenue. 2011. State and offshore 

regions statistics. Available at: http://www.onrr.gov/ONRRWebStats/USMap.aspx. 

U.S. Department of Labor. Bureau of Labor Statistics. 2010. Consumer Price Index. All urban 

consumers (CPI-U). Available at: ftp://ftp.bls.gov/pub/special.requests/cpi/cpiai.txt

Willis Group Holdings. 2009. 2009 Willis energy market review. March.
A-1 

APPE NDIX A. OFFS HOR E PIPE LINE CONS TR UCTION COS TS

When BOEM develops the exploration and development (E&D) scenarios for lease sales, 

Five-Year Programs, and other studies, the staff estimates the new pipeline miles needed to 

transport the additional forecasted production. An E&D scenario projects the number of pipeline 

miles to be constructed each year. Pipeline construction costs might vary by water depth, 

particularly if the pipeline is on the slope or in the deepwater region. 

Section A.1 describes the dataset used to estimate the costs while Section A.2 summarizes 

the cost estimates.

A.1 DATA SOURCES

Gaul (2009) examined the capability added to the U.S. natural gas pipeline system during 

2008. The report references the Natural Gas Pipeline Project Database developed by the U.S. 

Department of Energy (USDOE) Energy Information Administration (EIA). The database has 

several key features pertaining to this project. First, offshore Gulf of Mexico (GOM) pipelines 

can be identified through a “GM” entry for either the beginning region or the end region (two 

variables in the database). Second, the database contains the in-service year, the cost in millions 

of dollars, and the number of miles. With the understanding that the figures reflected the 

projected cost and not necessarily the actual final cost (USDOE EIA 2010), ERG requested, and 

USDOE EIA supplied, a copy of the database. The rest of the data and analysis presented in this 

appendix is done so with this understanding.30

ERG identified 12 natural gas pipeline projects that were carried out in the offshore GOM 

region since 2005 and had complete data. Table A-1 presents the project name, in-service year, 

cost in millions of dollars, and miles for each pipeline project. 

The Natural Gas Pipeline Project Database did not record the water depth for each project. 

ERG used several approaches to obtain this information. Some water depths are taken from 

project descriptions. For others, ERG identified the Outer Continental Shelf (OCS) block in 

which the production structure was located and then found the water depth in that block. Table 

A-2 displays the source and the water depth in feet for each project. 

A.2 COST ESTIMATES

ERG converted all costs into 2008$ using the Consumer Price Index (CPI) (USDOL BLS 

2010). In cases where the project has a future date, ERG assumed that the cost corresponded to 

the most recent year in the database (i.e., 2010). Using the converted figures, ERG calculated the 

cost per mile for each project and averaged the cost per mile within each water depth range (see 

Table A-3). 

 

30 ERG did not identify any other data source with more complete cost data where offshore wells could be 

specifically extracted for analysis.
A-2 

Table A-1 

Offshore GOM Pipeline Projects Since 2005

Project 

Number Project Name Year Cost (Million$) Miles

1 Energy Bridge Connection Line 2005 5 8 

2 Tenneco Triple-T Extension 2007 22 6.23

3 MPEH Pipeline Project 2012 120 97

4 Cleopatra Gathering System Phase 2 2007 36 21

5 Enbridge Shenzi Lateral 2007 65 11

6

Enterprise Constitution Gathering 

Pipeline 2006 48 32

7 Okeanos Thunder Horse Segment 2006 50 26

8 Enbridge Neptune Deepwater Project 2008 50 29

9 WFS Blind Faith Extension 2008 255 71

10 Walker Ridge Gathering 2011 500 190

11

Enterprise Independence Trails 

Offshore Line 2006 209 140

12 Perdido Norte Projects 2010 250 184

Source: USDOE EIA 2010

Table A-2 

Pipeline Project Water Depths 

Project 

Number Project Name

Water 

Depth 

(ft) 

Source

1 Energy Bridge Connection Line 300 Offshore Magazine 2005

2 Tenneco Triple-T Extension 415 USDOI BOEMRE 2010

3 MPEH Pipeline Project 210 Red Orbit 2005

4 Cleopatra Gathering System Phase 2 4000 Sauer and Wiseman 2006

5 Enbridge Shenzi Lateral 4300 Rigzone 2006

6 

Enterprise Constitution Gathering 

Pipeline 5128 SubseaIQ 2010

7 Okeanos Thunder Horse Segment 6000

Offshore-Technology 

2010a

8 Enbridge Neptune Deepwater Project 4221 Antani, et al. 2008

9 WFS Blind Faith Extension 7000 Williams 2010

10 Walker Ridge Gathering 7000 Rigzone 2009

11

Enterprise Independence Trails 

Offshore Line 8000

Offshore-Technology 

2010b

12 Perdido Norte Projects 8000 Tyson 2007
A-3 

Table A-3 

Offshore Pipeline Projects From 2005

Project Name Year

Cost

(Million$)

Cost

(Millions, 

2008$) Miles

Water 

Depth (ft)

Water 

Depth (m)

Water Depth

Range

Cost

(Millions, 

2008$/Mile)

Average Cost

(Millions, 

2008$/Mile 

by Water 

Depth)

Energy Bridge Connection Line 2005 $5 $5.51 8 300 91.44 60–200 $0.69 $1.32

Tenneco Triple-T Extension 2007 $22 $22.84 6.23 415 126.49 60–200 $3.67 $1.32

MPEH Pipeline Project 2012 $120 $118.59 97 210 64.01 60–200 $1.22 $1.32

Cleopatra Gathering System 

Phase 2 2007 $36 $37.38 21 4000 1219.20 800–1,600 $1.78 $2.33

Enbridge Shenzi Lateral 2007 $65 $67.50 11 4300 1310.64 800–1,600 $6.14 $2.33

Enterprise Constitution 

Gathering Pipeline 2006 $48 $51.26 32 5128 1563.01 800–1,600 $1.60 $2.33

Okeanos Thunder Horse 

Segment 2006 $50 $53.40 26 6000 1828.80 800–1,600 $2.05 $2.33

Enbridge Neptune Deepwater 

Project 2008 $50 $50.00 29 4221 1286.56 1,600–2,400 $1.72 $2.76

WFS Blind Faith Extension 2008 $255 $255.00 71 7000 2133.60 1,600–2,400 $3.59 $2.76

Walker Ridge Gathering 2011 $500 $494.11 190 7000 2133.60 1,600–2,400 $2.60 $2.76

Enterprise Independence Trails 

Offshore Line 2006 $290 $309.71 140 8000 2438.40 2,400+ $2.21 $1.72

Perdido Norte Projects 2010 $250 $247.06 184 8000 2438.40 2,400+ $1.34 $1.72

Source: USDOE EIA 2010, calculated by ERG
A-4 

The Enbridge Shenzi Lateral project is an outlier with a cost of $6.14 million per mile, nearly 

twice that of the next most expensive pipeline. ERG recalculated the average cost per mile by 

water depth without the Shenzi project, see Table A-4. There were no projects in the 0–200 foot 

or 650–2,600 foot ranges (0–60, 200–800 m). 

Table A-4 

Average Cost Per Mile (Millions, 2008$) by Depth Range

Water Depth (ft) Water Depth (m)

Average Cost Per 

Mile (Millions, 

2008$)

0–200 0–60 n/a

200–650 60–200 $1.32

650–1,300 200–400 n/a

1,300–2,600 400–800 n/a

2,600–5,200 800–1,600 $1.80

5,200–8,000

a 

1,600–2,400 $2.76

8,000+ 2,400+ $1.72 a 

Source: Calculated by ERG

This average fell from 2.33 in Table A-3 after the Shenzi project 

was excluded. 

ERG used regression analysis to estimate average costs per mile for the water depth ranges in 

which no projects were identified. ERG estimated a linear relationship between water depths and 

construction costs per mile using 11 data points taken from the projects listed in Table A-2, 

excluding the Shenzi outlier. ERG then used the midpoint of each water depth (m) range to 

estimate an average construction cost for that range. The equation describing the relationship is: 

Cost per Mile ($ thousand) = $1,751 + (0.21)*Water Depth (m) 

Table A-5 presents the estimates based on this relationship. 

Table A-5 

Estimated Cost Per Mile by Water Depth (Thousands, 2008$)

Water Depth Range (m)

Water Depth

Midpoint (m)

Line Est. Cost 

Per Mile 

($ Thousand)

0–60 30 $1,760

60–200 130 $1,780

200–400 300 $1,810

400–800 600 $1,880

800–1,600 1,200 $2,000

1,600–2,400 2,000 $2,170

2,400+ 3,000 $2,380

 Source: ERG estimates
A-5 

A.3 LITERATURE CITED

Antani, J.K., W.T. Dick, D. Balch, and T. van der Leij. 2008. Offshore Technology Conference, 

5–8 May 2008, Houston, Texas, USA. Design, fabrication and installation of the Neptune 

Export Lateral PLETs. Available at: 

http://www.onepetro.org/mslib/servlet/onepetropreview?id=OTC-19688-MS&soc=OTC. 

Gaul, D. 2009. Expansion of the U.S. natural gas pipeline network: additions in 2008 and 

projects through 2011. U.S. Department of Energy. Energy Information Administration. 

Office of Oil and Gas. September. Available at: 

http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2009/pipelinenetwork/pipeli

nenetwork.pdf

Offshore Magazine. 2005. World trends and technology for offshore oil and gas operations. 

Energy bridge delivers LNG to GoM. June 1, 2005. Available at: http://www.offshoremag.com/index/article-display/230879/articles/offshore/volume-65/issue-6/pipelinetransportation/energy-bridge-delivers-lng-to-gom.html. 

Offshore-Technology. 2010a. Industry projects. Thunder Horse field, Gulf of Mexico, USA. 

Available at: http://www.offshore-technology.com/projects/crazy_horse/. 

Offshore-Technology. 2010b. Industry projects. Independence Hub, Gulf of Mexico, USA. 

Available at: http://www.offshore-technology.com/projects/independence/. 

Red Orbit. 2005. McMoRan Exploration Co. Updates Gulf of Mexico and Gulf Coast 

exploration and development and Main Pass Energy Hub(TM) activities. October 3, 2005. 

Available at: 

http://www.redorbit.com/news/science/258602/mcmoran_exploration_co_updates_gulf_of_

mexico_and_gulf_coast/. 

Rigzone. 2006. E&P News: Industry news, stories, analysis, and editorial. June 20, 2006. 

Enbridge to extend GoM infrastructure to connect gas from Shenzi Field. Available at: 

http://www.rigzone.com/news/article.asp?a_id=33301. 

Rigzone. 2009. E&P News: Industry news, stories, analysis, and editorial. July 29, 2009. 

Enbridge proposes $500MM Walker Ridge gathering system for GOM. Available at: 

http://www.rigzone.com/news/article.asp?a_id=78717. 

Sauer, S.R., and J. Wiseman. 2006. Offshore Technology Conference, held 1 May-4 May in

Houston, Texas. Commissioning and startup of the Caesar and Cleopatra Mardi Gras 

deepwater pipelines. Available at: 

http://www.onepetro.org/mslib/app/Preview.do?paperNumber=OTC-18169-

MS&societyCode=OTC. 

SubseaIQ Deepwater and Subsea Projects.2010. Constitution. Available at: 

http://www.subseaiq.com/data/PrintProject.aspx?project_id=150. 
A-6 

Tyson, Ray. 2007. Petroleum News, Vol. 12, No. 32, August 12, 2007. Shell group chooses 

subsea pipelines over FPSO for offshore Perdido development. Available at: 

http://www.petroleumnews.com/pntruncate/328822294.shtml. 

U.S. Department of the Interior, Bureau of Ocean Energy Management, Regulation, and 

Enforcement. 2010. Offshore energy and minerals management. OCS related incidents. Gulf 

of Mexico OCS Region. Available at: http://www.boemre.gov/incidents/SigPoll2009.htm. 

U.S. Department of Labor. Bureau of Labor Statistics. 2010. All urban consumers – (CPI-U). 

U.S. city average. All items. 1982–84=100. Available at: http://www.bls.gov/cpi. 

U.S. Department of Energy. 2010. Energy information administration. Natural gas pipeline 

project database. Extraction requested 11/23/10. 

The Williams Companies, Inc. 2010. Company Web site. Gulf Coast profile. Available at: 

http://www.williams.com/gulfcoastprofile/#. 
B-1 

APPE NDIX B . S TR UCTUR E DE COMMIS S IONING COS TS

On October 15, 2010, BOEMRE (now BOEM) issued a N otice to Lessees and Operators 

(NTL) with guidance on decommissioning wells and structures (USDOI BOEMRE 2010). In 

particular, the definition of when decommissioning takes place changes from one year after a 

lease terminates (i.e., a lease basis) to when a well or platform stops production for 5 years or 

more (i.e., a well and structure basis). Kaiser (2010) estimates that there are nearly 5,200 wells 

that meet the new definition for decommissioning. Presumably, a proportionate number of 

structures to which those wells are attached also would need to be decommissioned. 

Section B.1 describes the data sources used in this analysis. Section B.2 presents the 

estimated costs for decommissioning production structures in the GOM and compares them with 

decommissioning costs estimated for production structures in the Pacific OCS region. Section 

B.3 describes of the cost items included in the estimates. Section B.4 reviews the assumptions 

and methodology used to arrive at the estimated costs. 

B.1 DATA SOURCES

Kaiser et al. (2009a,b) provides information on actual decommissioning costs for platforms 

in the GOM from 2003 to 2008 in water depths ranging from 0 to approximately 90+ m (300+ 

ft). Proserv Offshore (2009) provides engineering estimates, based on r epresentative platforms 

and structures in water depths ranging from 400 to 8,000 f eet (approximately 120 m to over 

2,400 m). The latter report also focuses strictly on GOM structures. These two reports form the 

basis of the updated decommissioning costs in MAG-PLAN. 

B.2 DECOMMISSIONING COST ESTIMATES

B.2.1 Cost Estimates

Table B-1 presents the costs of decommissioning platforms and other structures in the GOM. 

These costs were derived from Proserv (2009) and Kaiser et al. (2009a, b). Costs are presented 

for the platform/structure types currently found in the GOM: 

• Fixed platforms (including compliant towers)

• Spars

• Mini-tension leg platforms (mini-TLPs)

• TLPs 

• Semisubmersibles
B-2 

Table B-1 

Cost of Platform/Structure Decommissioning in the GOM by Water Depth (Thousands, 2008$)

Water Depth Assumed Type of 

Platform/Structure

With 

Explosives a

Without 

Meters Feet Explosives

0–60 0–200 Fixed Platform $1,528 $1,757

60–200 200–650 Fixed Platform $4,445 $5,111

200–400 650–1,300 Fixed Platform NA $40,525

400–800 1,300–2,600

Mini-TLP/Spar/Fixed 

Platform NA $45,198

800–1,600 2,600–5,200 Semisubmersible/TLP/Spar NA $25,133

1,600–2,400 5,200–8,000 Semisubmersible/Spar NA $24,973

,2400+ 8,000+ Semisubmersible NA $16,692 a

Source: Kaiser et al. 2009a,b; Proserv 2009

In 400–800 m depths, ERG assumed: 33 percent of platforms/structures are spars; 33

percent are mini-TLPs; and 33 percent are fixed platforms represented by Bullwinkle at 400 

m. In 800–1,600 m depths, ERG assumed: 4 percent are semisubmersibles, 46 percent are 

spars, 33 percent are TLPs, and 17 percent are mini-TLPs. In 1,600–2,400 m depths, ERG

assumed: 44 percent are spars and 56 percent are semisubmersibles (based on information 

collected by Proserv 2009).

Note that decommissioning with explosives is less expensive than decommissioning without 

explosives; however, decommissioning costs with explosives were available only for water 

depths up to 200 meters. The most expensive types of structures to decommission are those in 

water depths ranging from 200 to 800 meters (i.e., TLPs, mini-TLPs, spars, and fixed platforms). 

Floating production structures, such as semisubmersibles, are two to three times less expensive 

to decommission. 

The costs range from $1.5 million to $5.1 m illion for water depths up to 200 m eters. For 

water depths between 200 meters and 800 m eters, decommissioning costs range from $40.5 

million to $45.2 million. For water depths beyond 800 meters, the costs drop to between $16.7 

million and $25.1 million. 

Table B-2 presents the estimated costs for decommissioning production structures in the 

Pacific OCS, taken from Proserv Offshore (2010). The costs vary by water depth and weight and 

range from $12.0 m illion to $155.9 m illion. The cost assumptions include the need to import 

derrick barges from the GOM while excluding the use of explosives, thus leading to the higher 

costs. 
B-3 

Table B-2 

Estimated Costs for Decommissioning Platforms in the Pacific OCS

Platform 

Decommissioning 

Cost

Water Depth 

(ft)

Estimated 

Removal Weight 

(tons) Year Installed

Gina $12,022,672 95 1,006 1980

Hogan $34,453,019 154 3,672 1967

Edith $29,178,537 161 8,038 1983

Houchin $33,027,029 163 4,227 1968

Henry $18,621,649 173 2,832 1979

PlatformA $25,595,019 188 3,457 1968

PlatformB $30,548,957 190 3,457 1968

Hillhouse $26,025,227 190 3,100 1969

PlatformC $23,683,643 192 3,457 1977

Gilda $42,788,799 205 8,042 1981

Irene $32,645,792 242 7,100 1985

Elly $21,360,859 255 9,400 1980

Ellen $35,919,110 265 9,600 1980

Habitat $28,653,889 290 7,564 1981

Grace $41,645,339 318 8,390 1979

Hidalgo $67,918,547 430 21,050 1986

Hermosa $80,351,462 603 27,330 1985

Harvest $88,278,478 675 29,040 1985

Eureka $94,234,596 700 29,000 1984

Gail $88,839,896 739 29,993 1987

Hondo $91,690,506 842 23,550 1976

Heritage $149,600,043 1,075 56,196 1989

Harmony $155,913,807 1,198 65,089 1989

Source: Proserv 2010

B.2.2 Year of Cost Estimates

All costs in Table B-1 are representative of 2008 costs. Although Proserv’s report is dated 

October 2009, ERG assumed that the costs were gathered primarily during 2008 and early 2009. 

The Kaiser et al. (2009a,b) reports provide costs only on a nominal basis covering the years 2003 

through 2008. These costs could not be disaggregated by year; however, ERG used additional 

information to approximate costs in 2008$ for these shallow-water platforms. In addition to the 

average costs of platform removals, the report also indicates the number of platforms removed 

by year. The median platform-year is 2006 (that is, roughly half of the platforms reported were 

decommissioned prior to 2006 and half after 2006); therefore, ERG assumed that all costs were 

in 2006 dollars. Proserv (2009) estimated a decommissioning price index for the GOM over the 

years of interest with an inflation factor of approximately 16 percent for the 2006 to 2008 period. 
B-4 

ERG used this index to convert the costs presented in Kaiser et al. (2009a,b) from 2006$ to 

2008$. 

B.3 COST ITEMS INCLUDED IN ESTIMATES

The costs of platform/structure decommissioning are organized to include the costs of: 

• Platform preparation, which includes flushing hydrocarbons from lines; cutting deck 

equipment to be removed; and cutting electrical, tubing, and piping connections. 

• Structure removal and towing, including severing of tendons, cables, chains, and piles. 

• Site clearance, which includes checking the site for removal completeness (e.g., searching for 

and clearing any remaining debris).

To the extent possible, the costs do not include those for: 

• Plugging and abandoning wells. 

• Decommissioning pipelines. 

• Disposal of platforms and structures onshore. 

ERG could not ensure that the platform removal costs reported by Kaiser et al. (2009a,b) 

excluded disposal costs. However, nearly all platforms discussed in the article were reefed (i.e., 

left in place below the water line, toppled, or towed and dropped into shallow water for use as 

artificial reefs). Thus, the costs for fixed-platform removal reported by Kaiser et al. (2009a,b) are 

unlikely to include many costs attributable to onshore disposal. For the most part, costs for 

structures estimated by Proserv (2009) did not include any onshore disposal costs and, in the 

instances in which they did, ERG removed them when making estimates.

For fixed platforms, costs included those for removal of conductors. Costs for removing 

conductors were divided between conductor removals using explosives and conductor removals 

using abrasion. ERG assumes explosives are not used below 200 m (650 ft), based on the fact 

that Proserv (2009) did not estimate costs for explosive removal of conductors for any fixed 

platforms below this depth. 

For other deepwater structures (spars, mini-TLPs, TLPs, and semisubmersibles), Proserv 

(2009) included the costs of conductor removal with the costs of plugging and abandoning 

(P&A) wells. The costs for conductor removal were not separable from P&A costs. We assume 

that Proserv did this because the conductor removal activity is best done at the time wells 

associated with these deepwater structures are abandoned, and these costs are not normally 

incurred at the time of removal of these tethered structures.

B.4 KEY ASSUMPTIONS

The following sections provide information on the sources used and the assumptions made 

for each type of platform/structure at each depth. The assumptions about which structures are 

present at each depth rely on information from Proserv (2009), which provides data by type and 

by depth for all structures in the GOM in water deeper than 400 ft (approximately 120 m). ERG 

used these data to provide the structure-type breakout by depth shown in Table B-1. 
B-5 

B.4.1 Fixed Platforms 

B.4.1.1 Fixed Platforms (0 to 60 m)

ERG derived costs for fixed platforms in this depth range from Kaiser et al. (2009a,b) using 

average platform preparation and removal costs for platforms in the 0 to 100 ft and 100 to 200 ft 

depth ranges (0 to 60 m combined). ERG approximated costs for explosive and abrasive removal 

of conductors using information from Proserv (2009). The Proserv study determined that when 

explosives are used, the total removal costs for a fixed platform (including preparation costs) are 

15 percent lower than those incurred when abrasive techniques are used (see Proserv 2009, Table 

4.3). To derive the cost difference, ERG assumed that 80 percent of conductors at platforms in 

the 0 t o 60 m depth range are removed using explosives. To calculate the average cost of 

explosive removal, ERG applied this assumption to the overall average platform preparation and 

removal costs. After calculating the average platform removal cost under an explosive removal 

scenario, ERG multiplied this estimate by 1.15 to estimate platform removal costs under a 

nonexplosive removal scenario. As Table B-1 shows, the costs of decommissioning fixed 

platforms in the GOM in 0 to 60 m water depth are estimated to be $1.5 million when explosives 

are used and $1.8 million when abrasive techniques are used. 

B.4.1.2 Fixed Platforms (60 to 200 m)

Kaiser et al. (2009a,b) also provides information on f ixed platform costs for platforms in 

depths from 60 to roughly 90 m. Proserv’s (2009) study provides information on fixed platform 

costs from about 120 to 200 m. ERG used both of these sources to derive the average cost of 

platform removal in the 60 to 200 m water depth range. 

The first step was to identify average costs for explosive and abrasive removal of platforms. 

Proserv (2009) provided information on ni ne platforms in this depth range that allowed us to 

distinguish between platforms where explosive methods were implemented (five) and those 

where abrasive removal techniques were implemented (four). Proserv estimates that the cost of 

explosive removal techniques is 15 percent lower than the cost of abrasive removal techniques. 

ERG calculated the alternative scenario for each of the nine platforms using this estimate. Where 

the Proserv report estimated costs assuming the use of explosives, ERG multiplied the platform 

removal costs by 1.15 to approximate the costs of a nonexplosive removal scenario. Where the 

report assumed abrasive techniques were used, ERG divided the platform removal costs by 1.15 

to approximate costs under an explosive removal scenario. With that, ERG calculated the 

average cost of platform removal under each scenario in the 120 to 200 m water depth range. 

To separate costs in Kaiser et al. (2009a,b) by explosive versus nonexplosive removals, ERG 

used the average costs for platform preparation and removal in the 200 to 300+ ft range (60 to 

90+ m) and the same method described in Section B.4.1.1 for calculating such costs in the 0 to 

60 m water depth range. 

ERG assumed that within the 60 t o 200 m water depth range, 80 p ercent of all structures 

would be fixed platforms in the 60 to 100 m water depth range. Thus, only 20 percent of 

structures would be in the 100 to 200 m range. Under this assumption ERG created a weighted 

average cost for both explosive and nonexplosive removal using the average costs derived using 

Kaiser et al. (2009a,b) (80 percent) and the average costs derived using Proserv (2009) (20 

percent). As Table B-1 shows, costs for platform decommissioning in this depth range are 

expected to average $4.4 million (explosive removal) and $5.1 million (abrasive removal). 
B-6 

B.4.1.3 Fixed Platforms (200 to 400 m)

Only Proserv (2009) provides information on the cost of removing platforms at depths of 200 

to 400 meters. According to its information, only fixed platforms (and one compliant tower) are 

currently used in this depth range. Proserv assumed no pl atforms in this depth range use 

explosives; therefore, we do not calculate an alternative scenario. 

The average cost reported in Table B-1 for fixed platforms in the 200 to 400 m depth range is 

$40.5 million. The cost is derived through a s imple average of all the estimated costs of the 

representative platforms selected by Proserv at these depths. As the table indicates, the cost of 

platform decommissioning rises dramatically for fixed platforms in water depths greater than 200 

m.

B.4.2. Deepwater Structures (400 to 2,400+ m)

B.4.2.1 General Assumptions

In water depths greater than 400 m , fixed platforms are rare. The three structures (two of 

which are compliant towers) are represented by costs estimated in the Proserv report for one 

fixed platform in 400 m water depth. All of these fixed structures are in 400 t o 800 m water 

depths. 

Costs for all other deepwater structures (divided into spars, mini-TLPs, TLPs, and 

semisubmersibles) are tailored to each assumed water depth. Proserv provides only one depth 

assumption for each structure, but it also provides scaling values that can be used to modify costs 

depending on the depth. Depth is a major cost driver in all of the deepwater structures (except 

fixed platforms) because it defines the length of the chain/mooring lines/tendons used to attach 

these structures to the seafloor. The longer these are, the more difficult and time consuming their 

removal. Other costs are less depth sensitive. 

Proserv provides information for each deepwater GOM structure, including type of structure, 

number of tethers (i.e., mooring chains and lines or tendons), deck weight, and water depth.31

B.4.2.2 Specific Assumptions by Water Depth

ERG’s assumptions on typical water depths, number of tendons by water depth range, and type 

of structure are discussed below in Section B.4.2.3. 

In the 400 to 800 m water depth range, Proserv indicates that there are three fixed platforms 

(two of which are compliant towers), three spars, two mini-TLPs, one TLP, and one 

semisubmersible. ERG extrapolated an overall average cost at this depth range by using the 

estimates for the average costs for three types of structures. ERG assumed that 33 pe rcent of 

 

31 ERG found some issues in the Proserv report. The costs on a p er line per ft water-depth basis for line 

removal appeared to include mooring chain removal costs, even though mooring chain costs per line per ft water 

depth were reported separately. ERG recalculated the costs per line per ft water depth for mooring line removal only 

and used both costs separately. Additionally, ERG determined that various contingency costs were not being applied 

consistently, and no reason was indicated for the differences in application. For example, nearly all mobilization and 

demobilization costs for barges and tugs across all types of structures were assigned no weather or work 

contingencies, but for semisubmersibles, contingencies were applied to barges and tug mobilization and 

demobilization costs. As another example, in nearly all cost estimates, weather contingencies were calculated at 20 

percent of costs. However, for site clearance costs for two types of structures, the contingency was calculated at 10 

percent rather than 20 percent, even though in one case the line item was labeled 20 percent. ERG corrected the 

contingency cost where it believed a co ntingency was incorrect or incorrectly applied. However, these changes 

resulted in cost differences that were not substantial. 
B-7 

structures are fixed platforms, 33 percent are mini-TLPs (costs for mini-TLPs and TLPs at this 

depth should be similar according to information in Proserv’s report), and 33 percent are spars 

(the cost for one semisubmersible at this depth should have little impact on ove rall average 

costs). The overall average decommissioning cost for this depth range, shown in Table B-1, is 

estimated to be $45.2 million per structure, primarily due to the relatively high cost of removing 

fixed platforms. As the table shows, however, despite the substantial increase in depth, average 

decommissioning costs are not much higher than the average decommissioning costs in the 200 

to 400 m water depth range. 

In the 800 t o 1,600 m water depth range, Proserv indicates that there are four mini-TLPs, 

eight TLPs, 11 spars, and one semisubmersible. ERG calculates an overall average cost for this 

depth range based on each structure type’s proportion of the total structures found in the depth 

range, again, based on the information in Proserv’s (2009) report (see footnotes to Table B-1). 

ERG uses this same approach in the 1,600 to 2,400 m water depth range, where Proserv reports 

that four spars and five semisubmersibles are operating. Only one semisubmersible operates in 

the 2,400+ range. 

As Table B-1 shows, average decommissioning costs actually decline at greater depths 

because fewer spars and more TLPs and semisubmersibles (which are much less expensive to 

decommission) are installed. In 800 to 1,600 m water depths, average costs are $25.1 million per 

structure, and in 1,600 to 2,400 m water depths, average costs are $25.0 million per structure. In 

the 2,400+ m water depth range, average costs decline even more noticeably. ERG estimated that 

the average cost at this depth, assuming only semisubmersibles operate there, was only $16.7 

million per structure for decommissioning.

B.4.2.3 Specific Assumptions by Structure Type

Other structure-specific assumptions worth noting include: 

Spars: Two cost estimates are available from Proserv (2009) for deck removal, depending on 

deck weight (greater than or less than 5,000 short tons [st]). ERG assumed that the deck weight 

was greater than 5,000 st for all spars, based on data provided by Proserv (2009) showing few 

spars with deck weights below 5,000 st. To adjust costs for water depths, ERG made the 

following assumptions based on the Proserv structure data: 

• 400 to 800 m water depth: ERG assumed 12 mooring lines and a 2,500 ft (750 m) water 

depth. 

• 800 to 1,600 m water depth: ERG assumed 12 mooring lines and a 4,000 ft (1,200 m) water 

depth. 

• 1,600 to 2,400 m water depth: ERG assumed nine mooring lines and a 6,000 ft (1,800 m) 

water depth.

Mini-TLPs: Two cost estimates are available for deck removal on mini-TLPs as well. ERG 

assumed that the deck weighs less than 5,000 st for mini-TLPs in the 400 to 800 m water depth 

range. In the 800 to 1,000 m water depth range, however, deck weights were split evenly. ERG 

used the average of costs estimated by Proserv for decks weighing less than 5,000 st and those 

for decks weighing more than 5,000 st to represent the split between deck weights in this water 

depth range. In addition, ERG scaled platform preparation costs at the Proserv-suggested cost of 

$108 per deck-ton, using 3,000 st and 5,000 st as the average for mini-TLPs in 400 to 800 m and 
B-8 

800 to 1,600 m water depths, respectively. To adjust costs for water depths, ERG made the 

following assumptions based on Proserv’s structure data: 

• 400 to 800 m water depth range: ERG assumed six tendons at 1,700 ft (520 m) water depth 

• 800 to 1,600 m water depth range: ERG assumed six tendons at 2,900 ft (880 m) water depth 

TLPs: ERG used TLP costs only for such structures in the 800 to 1,600 m depth. For the 

estimate in Table B-1, ERG used the costs Proserv derived for the representative structure at this 

depth (with some minor corrections to contingencies). 

Semisubmersibles: ERG estimated average costs for semisubmersibles in 1,600 to 2,400 m 

water depth and 2,400+ water depth. To adjust costs for water depths, ERG made the following 

assumptions based on Proserv’s structure data: 

• 1,600 to 2,400 m water depth: ERG used the costs Proserv developed for their selected 

representative semisubmersible with 16 mooring lines in 6,000 ft (1,800 m) water depth. 

• 2,400+ m water depth: ERG assumed 16 mooring lines and a 9,200 ft (2,800 m) water depth. 
B-9 

B.5 LITERATURE CITED

Kaiser, M., R. Dodson, and M. Foster. 2009a. Gulf of Mexico structure removal costs examined. 

Oil & Gas Journal 107(23):37–42. June 15. 

Kaiser, M., R. Dodson, and M. Foster. 2009b. An update on the cost of decommissioning in the 

Gulf of Mexico, 2003 to 2008. International Journal of Oil, Gas and Coal Technology

2(2):89–120. 

Kaiser, M. 2010. Gulf of Mexico decommissioning market review 2010. Webinar. September 23, 

2010. 

Proserv Offshore. 2010. Decommissioning cost update for removing Pacific OCS Region 

Offshore oil and gas facilities, January 2010, Volume 1. 

Proserv Offshore. 2009. Gulf of Mexico deep water decommissioning study review of the state 

of the art for removal of GOM US OCS oil & gas facilities in greater than 400’ water depth. 

October 2009. 

U.S. Department of the Interior, Bureau of Ocean Energy Management, Regulation, and 

Enforcement. (BOEMRE). 2010. Notice to lessees and operators of federal oil and gas leases 

and pipeline right of to way holders in the Outer Continental Shelf, Gulf Of Mexico OCS 

Region. Decommissioning guidance for wells and platforms. NTL No. 2010-G05. Issue date: 

September 15, 2010. Effective date: October 15, 2010. Available at: 

http://www.gomr.boemre.gov/homepg/regulate/regs/ntls/2010NTLs/10-g05.pdf
C-1 

APPE NDIX C. FPS O AND S UB S E A S YS TE M COS TS

MAG-PLAN allocates activity functions to IMPLAN industry sectors (See Section 2.3). One 

of the new activity functions added to MAG-PLAN 2012 is the installation of a FPSO (floating 

production, storage, and offloading) vessel and associated subsea system (Figure C-1). Sections 

C.1 and C.2 develop “typical costs” for a subsea system and FPSO, respectively, based on public 

data, for the purpose of splitting the costs between IMPLAN sectors 209 (Shipbuilding and 

repairing) and 206 (Mining and oil and gas field machinery).32

Figure C-1. Cascade and Chinook Fields with subsea completions and FPSO. 

 

32 The costs presented in Chapter 3 reflect a mix of possible floating production systems, while this appendix 

examines those for only the FPSO vessel. In keeping with the “no gap, no overlap” approach for costing, the values 

presented in Chapter 3 include the floating system and associated subsea components.
C-2 

C.1 SUBSEA TIEBACKS/WELL COMPLETIONS

C.1.1 Description

Subsea systems have one or more of the following components: subsea wells, manifolds, 

control umbilicals, pumping/processing equipment, and flow lines (USDOI MMS 2008). Figure 

C-1 shows the layout of Petrobras’ Cascade and Chinook fields with these different components. 

FSHR stands for “free standing hybrid riser,” where a steel pipe is supported by a near-surface 

buoyancy can (yellow in Figure C-1) and is connected to a flexible flow line to the FPSO 

(Technip n.d.). The surface part of a subsea system includes the control system and other 

production equipment (USDOI MMS 2008). USDOI MMS (2008) notes that, before 1993, fewer 

than 10 subsea completions per year were performed. The number jumped in 2001 and 2002 as 

the fields supplying the Na KiKa semisubmersible were drilled. The annual number of subsea 

completions took another jump in 2007, when Independence Hub went into operation (see Figure 

C-2). 

Source: USDOI MMS 2008

Figure C-2. Number of subsea completions per year. 
C-3 

C.1.2 TYPICAL COSTS

USDOI MMS (2008) reports that 85 pe rcent of all currently active deepwater fields use 

subsea systems, thus implying that project costs likely include subsea completion costs. To 

provide another estimate of “typical” costs, ERG examined the major suppliers. Five companies 

dominate the subsea production equipment market: Aker Solutions, Cameron International, DrilQuip, FMC, and Vetco Gray (General Electric Oil and Gas) (Kopits and Jones 2010). Between 

2007 and 2009, FMC held approximately 45 to 47 percent of the market, Cameron and Vetco 

Gray held about 17 to 16 percent each, Aker Solutions garnered 13 percent, and Dril-Quip held 

the remaining 7 pe rcent (Kopits and Jones 2010). ERG examined the press releases for each 

company from January 2009 through May 2010 for contract awards for subseabed equipment. 

These are listed in Table C-1. The announced contracts range from $11 million to $700 million, 

with an average value of $150 m illion and a third quartile value of $208 million (i.e., 75 

percentile in the distribution). Most of the orders for subsea production equipment during the 

2009 to mid-2010 period are for regions other than the GOM, but given the wide range of 

regions included in Table C-1, equipment costs for the GOM are likely to be in the same range. 

Because a subsea system might be completed with components from more than one vendor, ERG 

proposes to use $200 million (2008$) (i.e., the third quartile value in Table C-1) as a reasonable 

estimate for the cost of a subsea system. For comparison, the subsea system for the Chinook and 

Cascade fields costs approximately $200 million (FMC 2007). 

C.2 FPSOS

C.2.1 DESCRIPTION

A FPSO is a ship-like vessel (sometimes a 

converted tanker) moored at an offshore oil and 

gas field (Figure C-3). The vessel is equipped to 

receive, process, store, and offload hydrocarbons. 

Converting a tanker into a FPSO involves adding 

processing equipment and accommodations. The 

cargo capacity serves as storage for the treated 

product until it is transferred to shuttle tankers for 

transport to the shore. FPSOs operate in locations 

where the expense of adding subsea pipelines 

and/or onshore processing capabilities would 

make the field unprofitable due to the high cost of 

adding such capabilities.

Figure C-3. FPSO. 

Source: Wilhoit and Supan. 2009 SBM 

Offshore
C-4 

C.2.2 TYPICAL COSTS

Wilhoit and Supan (2009) list 105 ve ssels owned by contractors such as BW Offshore or 

SBM Offshore and 92 operator-owned vessels. For this study, ERG focused on the six vessels 

operating along the East Coast of Canada, the United States, and Mexico (including the GOM). 

These are listed in Table C-2. ERG could not find cost information for the three PEMEX vessels. 

The cost of converting an existing vessel to a FPSO (e.g., Pioneer) is approximately $740 

million. New vessels range from $1.6 billion to $2.35 billion Canadian ($1.18 billion to $1.95 

billion U.S. at the 1996 and 2005 exchange rates, respectively). 
C-5 

Table C-1 

Orders for Subsea Tiebacks and Completions (January 2009 through May 2010)

Number of Items Included

Company Year Region

Cost

(Millions, 

US$)

RiserSubsea boosting systemsESDV (emergency valve)Umbilicals Subsea power cablesTopside subsea control systemTie-in and connection systemSubsea treesManifoldSubsea wellheadsSurface treesSurface wellheadsSubsea separation module

Aker 2009 Korea $37 1 

Aker 2009 Brazil $37 8 1

Aker 2009 North Sea $50 9 9 

Aker 2009 Norwegian Sea $58 28 km 3 3 1 3

Aker 2009 North Sea $75 24 km 1 1 

Aker 2009 Barents $382 20 km 24 1 24 8

Aker 2010 Mediterranean $20 12 km 8 km 1 1 

Aker 2010 Brazil $254 61

Aker 2010 Australia $91 264 km

Aker 2010 Mediterranean $108 240 km

Cameron 2009 Gulf of Mexico $100 1 1 4 1 

Cameron 2009 Brazil $500 138

Cameron 2009 Gulf of Mexico $86 16

Cameron 2010 Gulf of Mexico $230 1 >1 12 4

Dril-Quip 2009 Gulf of Mexico $80 yes

Dril-Quip 2009 Brazil $180 yes
C-6 

Table C-1. 

Orders for Subsea Tiebacks and Completions (January 2009 through May 2010) (continued)

Number of Items Included

Company Year Region

Cost

(Millions, 

US)

RiserSubsea boosting systemsESDV (emergency valve)Umbilicals Subsea power cablesTopside subsea control systemTie-in and connection systemSubsea treesManifoldSubsea wellheadsSurface treesSurface wellheadsSubsea separation module

FMC 2007

Gulf of 

Mexico $200 2 1 4 3 

FMC 2009 Brazil $30 30 30

FMC 2009 Timor $60 yes 3 3

FMC 2009 North Sea $73 8 8 8

FMC 2009 Brazil $90 1

FMC 2009

Gulf of 

Mexico $82 1 9

FMC 2009 Angola $80 yes 1 1 6 6

FMC 2009 Brazil $75 2 12 4

FMC 2009 Ghana $210 2 19 8

FMC 2009 Angola $140 3

FMC 2010 North Sea $40 10 10

FMC 2010 Angola $65 yes yes

FMC 2010 Norwegian $62 2 2 1

FMC 2010 North Sea $210 10 9 2 8

FMC 2010 Brazil $400 <=107

GE 2009 Brazil $250 250

GE 2009 Brazil $11 4

GE 2010 Australia $700 yes yes 20 5 20

Sources: Aker 2010a–d and 2009a–f; Cameron 2010 and 2009a–c; Dril-Quip 2009a,b; FMC 2010a–e and 2009a–i; GE 2010 and 2009a,b.
C-7 

C.2.2.1 Pioneer

Pioneer will be the first FPSO to operate in the GOM OCS in the Cascade and Chinook 

fields. Petrobras selected BW Offshore, a Bermuda-incorporated Norwegian firm, to convert, 

install, and operate a FPSO. The contract is for up to eight years with a nominal value of $740 

million (BW Offshore 2007, Offshore-Technology 2010). BW Offshore, in turn, selected Keppel 

Offshore & Marine for the conversion, which was done in Singapore (BW Offshore 2009). ERG 

is using the value of the lease as a proxy for the value of the vessel. 

C.2.2.2 White Rose

Husky Energy is developing the White Rose field, east of St. John’s, Canada, with the 

SeaRose FPSO. Samsung Heavy Industries (South Korea) was responsible for the design, 

fabrication, commissioning and delivery of the hull, complete with accommodation, helideck, 

topsides support stools, and turret, while the topsides and installation took place in the 

Marystown, Newfoundland, shipyard (Ship Technology, 2009). First production was in 2005, 

and Husky noted that total capital costs for development were about $2.35 billion Canadian 

($1.95 billion U.S.). The cost appears to include seven or eight horizontal oil wells, 10 or 11 

water injectors, and two (required) gas injectors (Husky 2009). 

C.2.2.3 Terra Nova

The Terra Nova field was discovered in 1984 and came into production in 2002. The FPSO 

was built in a South Korean shipyard (Petro-Canada 1999). ERG found a reference to a 

preliminary startup capital cost estimate of $1.6 billion Canadian (Newfoundland and Labrador 

1996). 

C.2.2.4 Bourbon Opale

Wilhoit and Supan (2009) list the Bourbon Opale as new construction. However, the 

brochure on t he Norwegian Bourbon Offshore company Web site lists it a s a conversion 

(Bourbon Offshore n.d.). Beckman (2004) calls Bourbon Opale and Toisa Pisces (see Section 

4.2.5) “ecological” well test vessels with fluid storage and processing facilities. The Aker 

Langsten shipyard in Tomrefjord, Norway, built the original Bourbon Opale and handled the 

conversion. The topsides were built by The Expro Group in Reading, United Kingdom. The 

vessel is leased to PEMEX. ERG could not locate conversion cost information. 

C.2.2.5. Toisa Pisces

Sealion purchased a c able-laying vessel, converted it into an “ecological” well test vessel, 

and renamed it the Toisa Pisces. The conversion was done in Gdansk, Poland (Beckman 2004, 

Sealion n.d.). PEMEX also leases this vessel. ERG could not locate conversion cost information. 
C-8 

Table C-2 

FPSOs

Vessel Name

Sea Rose

(White Rose) Terra Nova Pioneer Bourbon Opale Toisa Pisces

Yuum K'ak 

Na’ab

FPSO Owner Husky

Suncor Energy

(Petro-Canada) BW Offshore

Bourbon 

Offshore Toisa Horizon BW Offshore

FPSO Operator Husky

Suncor Energy

(Petro-Canada BW Offshore

Bourbon 

Offshore Secunda Marine BW Offshore

Field Operator Husky

Suncor Energy

(Petro-Canada Petrobras PEMEX PEMEX PEMEX

Leased FPSO (Y/N) N N Y Y Y Y

Field or Location White Rose Terra Nova

Cascade, 

Chinoook Various Various KuMaZu

Country Canada Canada US GOM Mexico GOM Mexico GOM Mexico GOM

Construction Type New New Conversion New Conversion Conversion

Mooring System Type Internal Turret External Turret

Disconnectable 

Turret Buoy Turret

Dynamic 

Positioning Internal Turret

Max Oil Production 

(MBOPD) 105 32 80 15 20 200

Oil Storage Capacity 

(MBBLS) 630 550 600 36 20 2200

Operating Water 

Depth (m) 120 94 2,600 – – 100

Shipyard

South Korea, 

Canada South Korea

Keppel 

(Singapore) Norway Norway Singapore

Cost (in millions)

$2,350 

(Canadian)

$1,600 

(Canadian) $740 – – – 

Source: Wilhoit and Supan 2009
C-9 

C.2.2.6 Yu’um K’akna’ab

The Lord of the Seas (Yu’um K’akna’ab in Mayan) was built in the Sembawand Shipyard in 

Singapore (PEMEX 2006). 

C.2.3 FPSO Cost Estimate

As mentioned in Section C.2.2, there are only two estimates for new-build FPSOs in use in 

North American waters. The Terra Nova field FPSO has an estimated cost of $1.6 bi llion 

Canadian in 1996, which equates to about $1.176 billion 1996 U.S. dollars. Similarly, the White 

Rose FPSO’s estimated cost was $2.35 bi llion Canadian in 2005 ( about $1.95 i n 2005 U.S. 

dollars) (BCan 2010). In 2008 U.S. dollars, the costs are about $1.613 billion and $2.149 billion, 

respectively (USDOL BLS 2010). The average cost, rounded to the nearest $100 million, is $1.9 

billion.

This is only the cost for the vessel. A FPSO would be processing production from a subsea 

system. The data in Section C.1 provides an estimate of $200 million for a typical subsea system; 

thus ERG set the FPSO cost at $2.1 billion. 

C.3 LITERATURE CITED

Aker Solutions. 2010a. Company Web site. News release. Aker Solutions signs subsea contract 

with Repsol. February 4. Available at: 

http://www.akersolutions.com/Internet/MediaCentre/PressReleases/OilAndGas/AKPressRele

ase_1380141.htm. 

Aker Solutions. 2010b. Company Web site. News release. Aker Solutions with lowest bid for 

subsea frame Agreement. Jan 28. Available at: http://www.akersolutions.com/Internet/

MediaCentre/PressReleases/OilAndGas/AKPressRelease_1378042.htm. 

Aker Solutions. 2010c. Company Web site. News release. Large umbilical contract to Aker 

Solutions on Australian continental shelf. March 26. Available at:

http://www.akersolutions.com/Internet/

MediaCentre/PressReleases/OilAndGas/AKPressRelease_1397607.htm. 

Aker Solutions. 2010d. Company Web site. News release. Aker Solutions to supply subsea 

umbilicals to Noble Energy. April 9. Available at: http://www.akersolutions.com/Internet/

MediaCentre/PressReleases/OilAndGas/AKPressRelease_1401643.htm. 

Aker Solutions. 2009a. Company Web site. News release. Aker Solutions awarded fifth drilling 

riser contract by DSME. March 11. Available at:

http://www.akersolutions.com/Internet/MediaCentre/PressReleases/OilAndGas/AKPressRele

ase_1296799.htm. 

Aker Solutions. 2009b. Company Web site. News release. Aker Solutions to supply subsea 

boosting systems to Petrobras. November 23. Available at:

http://www.akersolutions.com/Internet/MediaCentre/PressReleases/OilAndGas/AKPressRele

ase_1356623.htm. 
C-10 

Aker Solutions. 2009c. Company Web site. News release. Visund and Troll subsea contracts to 

Aker Solutions. October 23. Available at: 

http://www.akersolutions.com/Internet/MediaCentre/PressReleases/OilAndGas/AKPressRele

ase_1349558.htm. 

Aker Solutions. 2009d. Company Web site. News release. Subsea equipment contract to Aker 

Solutions. March 30. Available at:

http://www.akersolutions.com/Internet/MediaCentre/PressReleases/OilAndGas/AKPressRele

ase_1301103.htm. 

Aker Solutions. 2009e. Company Web site. News release. Aker Solutions signs subsea EPC 

contract for Oselvar. June 10. Available at:

http://www.akersolutions.com/Internet/MediaCentre/PressReleases/OilAndGas/AKPressRele

ase_1321755.htm. 

Aker Solutions. 2009f. Company Web site. News release. Aker Solutions awarded BP tie-back 

contract for Ula. December 22. Available at:

http://www.akersolutions.com/Internet/MediaCentre/PressReleases/OilAndGas/AKPressRele

ase_1366424.htm. 

Bank of Canada (BCan). 2010. Exchange rate lookup for 1996 and 2005. Available at:

http://www.bankofcanada.ca/en/rates/can_us_lookup.html. 

Beckman, J. 2004. “Cleaner” well test vessels improve flaring, recovery in the Bay of 

Campeche. Offshore 64(9). September. Available at: http://www.offshoremag.com/offshore/en-us/index/article-tools-template.articles.offshore.volume-64.issue9.latin-america.cleaner-well-test-vessels-improve-flaring-recovery-in-bay-of-campeche.html. 

Bourbon Offshore Norway AS. n.d. Company Web site. Fleet. Bourbon Opale. Available at: 

http://www.bourbon-offshore.no/prod_images/doc_2_32.pdf. 

BW Offshore. 2009. The official naming ceremony of FPSO BW Pioneer took place in 

Singapore on 26 October. News release. Available at:

http://www.bwoffshore.com/en/News/Naming-ceremony-of-FPSO-BW-Pioneer/. 

BW Offshore .2007. BW Offshore selected to provide the FPSO to Petrobras for the Chinook 

Cascade oil fields in the US GoM. News release. August 21. Available at: 

http://cws.huginonline.com/B/136844/PR/200708/1148030_5.html. 

Cameron International Corporation. 2010. Company web site. News release. Cameron receives 

award for subsea systems from Chevron. January 4. Available at: http://www.c-am.com/content/ir/news_release.cfm?nr=2010. 
C-11 

Cameron International Corporation. 2009a. Company Web site. News release. Cameron enters 

into frame agreement with Petrobras, receives initial order for 111 subsea trees. September 

28. Available at: http://www.c-a-m.com/content/ir/news_release.cfm?nr=2009. 

Cameron International Corporation. 2009b. Company Web site. News release. Cameron receives 

$86 million order for offshore multiphase pumping systems. October 21. Available at:

http://www.c-a-m.com/content/ir/news_release.cfm?nr=2009. 

Cameron International Corporation. 2009c. Company Web site. News release. Cameron receives 

$100 million subsea systems order from BP under Gulf of Mexico frame agreement. January 

15. Available at: http://www.c-a-m.com/content/ir/news_release.cfm?nr=2009. 

Dril-Quip, Inc. 2009a. Company Web site. News release. Dril-Quip, Inc. awarded $80 million 

contract for subsea wellhead systems. March 23. Available at: http://phx.corporateir.net/phoenix.zhtml?c=100535&p=irol-newsArticle&ID=1268835&highlight=.

Dril-Quip, Inc. 2009b. Company web site. News release. Dril-Quip awarded $180 million 

contract for the supply of deepwater subsea wellhead systems. June 2. Available at:

http://phx.corporate-ir.net/phoenix.zhtml?c=100535&p=irolnewsArticle&ID=1294902&highlight=.

FMC Technologies, Inc. 2010a. Company Web site. News release. Statoil awards FMC 

technologies $40 million contract. January 25. Available at:

http://ir.fmctechnologies.com/releasedetail.cfm?ReleaseID=439978. 

FMC Technologies, Inc. 2010b. Company Web site. News release. Petrobras awards FMC 

Technologies $400 million subsea tree frame agreement. February 4. Available at:

http://ir.fmctechnologies.com/releasedetail.cfm?ReleaseID=442933. 

FMC Technologies, Inc. 2010c. Company Web site. News release. Total awards FMC 

Technologies $65 million contract. February 25. Available at:

http://ir.fmctechnologies.com/releasedetail.cfm?ReleaseID=447381. 

FMC Technologies, Inc. 2010d. Company Web site. News release. FMC Technologies receives 

$62 million contract to support Marulk Field development. March 8. Available at:

http://ir.fmctechnologies.com/releasedetail.cfm?ReleaseID=450265. 

FMC Technologies, Inc. 2010e. Company Web site. News release. Total awards FMC 

Technologies $210 million subsea contract to support Laggan-Tormore Field. April 6. 

Available at: http://ir.fmctechnologies.com/releasedetail.cfm?ReleaseID=457060. 

FMC Technologies, Inc. 2009a. Company Web site. News release. FMC Technologies awarded 

$80 million contract for BP operated deepwater projects. January 26. Available at:

http://ir.fmctechnologies.com/releasedetail.cfm?ReleaseID=361475. 
C-12 

FMC Technologies, Inc. 2009b. Company Web site. News release. FMC Technologies receives 

subsea systems orders for $82 million from BP for projects in Gulf of Mexico. February 2. 

Available at: http://ir.fmctechnologies.com/releasedetail.cfm?ReleaseID=363109. 

FMC Technologies, Inc. 2009c. Company Web site. News release. FMC Technologies awarded 

$30 million contract for StatoilHydro's Peregrino project. June 3. Available at : 

http://ir.fmctechnologies.com/releasedetail.cfm?ReleaseID=387873. 

FMC Technologies, Inc. 2009d. Company Web site. News release. FMC Technologies receives 

$60 million award for Eni's Kitan development. June 17. Available at : 

http://ir.fmctechnologies.com/releasedetail.cfm?ReleaseID=390396. 

FMC Technologies, Inc. FMC 2009e. Company Web site. News release. FMC Technologies to 

supply deepwater subsea separation system for Petrobras' Marlim field. August 19. Available 

at: http://ir.fmctechnologies.com/releasedetail.cfm?ReleaseID=404119. 

FMC Technologies, Inc. 2009f. Company Web site. News release. FMC Technologies awarded 

$73 million contract to supply subsea systems for StatoilHydro's Gullfaks field. August 24. 

Available at: http://ir.fmctechnologies.com/releasedetail.cfm?ReleaseID=404832. 

FMC Technologies, Inc. 2009g. Company Web site. News release. FMC Technologies awarded 

$75 million Roncador Module III contract. February 10. Available at:

http://ir.fmctechnologies.com/releasedetail.cfm?ReleaseID=364527. 

FMC Technologies, Inc. 2009h. Company Web site. News release. FMC Technologies receives 

$140 million gas exporting regulation manifold contract for BP operated Block 18. January 

15. Available at: http://ir.fmctechnologies.com/releasedetail.cfm?ReleaseID=359422. 

FMC Technologies, Inc. 2009i. Company Web site. News release. FMC Technologies to support 

Jubilee deepwater development. June 16. Available at : 

http://ir.fmctechnologies.com/releasedetail.cfm?ReleaseID=390192. 

FMC 2007. FMC Technologies, Inc. Company Web site. News release. FMC Technologies to 

supply subsea systems for Petrobras' Cascade & Chinook Projects offshore the U.S. Gulf of 

Mexico. October 9. Available at:

http://ir.fmctechnologies.com/releasedetail.cfm?ReleaseID=268100. 

GE 2010. General Electric. Company Web site. News release. GE oil & gas power generation 

and subsea equipment wins bring Gorgon Project awards to over $1.1 billion. March 3. 

Available at:

http://www.geoilandgas.com/businesses/ge_oilandgas/en/about/press/en/2010_press/030310a

.htm. 
C-13 

General Electric. 2009a. Company Web site. News release. GE Oil & Gas wins $11m contract 

with OGX of Brazil to supply advanced subsea wellhead technology. June 24. Available at:

http://www.geoilandgas.com/businesses/ge_oilandgas/en/about/press/en/2009_press/062409.

htm. 

General Electric. 2009b. Company Web site. News release. GE Oil & Gas wins $250 million 

contract from Petrobras to supply 250 subsea wellhead systems for Brazil offshore drilling 

projects. June 8. Available at:

http://www.geoilandgas.com/businesses/ge_oilandgas/en/about/press/en/2009_press/060809.

htm. 

Husky Energy Inc. 2009. Company Web site. Projects. White Rose. Available at:

http://www.huskyenergy.ca/operations/canadaseastcoast/projects/whiterose.asp. 

Kopits, S. R. and Ian Jones. 2010. Subsea production: more than just trees. Offshore 70(4) April 

1. Available at: http://www.offshore-mag.com/index/articledisplay/0783438926/articles/offshore/volume-70/Issue-4/subsea/Subsea-production-Morethan-just-trees.html. 

Lindsey Wilhoit and Chad Supan, Mustang Engineering. 2009. Worldwide survey of floating 

production, storage and offloading (FPSO) units. August. Poster. Available at:

http://www.offshore-mag.com/etc/medialib/platform-7/offshore/mapsand_posters.Par.96185.File.dat/2009FPSO-072409ADS.pdf. 

Newfoundland and Labrador. 1996. Government of Newfoundland and Labrador-Canada. Terra 

Nova Development Project. News release. August 5. Available at:

http://www.releases.gov.nl.ca/releases/1996/exec/0805n03.htm. 

Offshore-Technology 2010. Offshore-technology.com Industry Projects. Cascade and Chinook 

subsea development, Gulf of Mexico. Available at: http://www.offshoretechnology.com/projects/cascadechinook/ and http://www.offshoretechnology.com/projects/cascadechinook/specs.html. 

PEMEX. 2006. Annual report 2006. Available at: http://www.pep.pemex.com/RepAnu2006/. 

Petro-Canada. 1999. Annual report. Available at:

http://www.sedar.com/GetFile.do?lang=EN&docClass=2&issuerNo=00002127&fileName=/

csfsprod/data18/filings/00250658/00000001/w%3A%5CALOPEZ%5Csedar%5C00filing%5

CAR-E.pdf. 

Sealion Shipping Ltd. n.d. Company Web site. List of vessels. Available at:

http://www.sealionshipping.co.uk/sitemap.htm. 

Ship Technology. 2009. Ship-Technology.com. Projects. Available at: http://www.shiptechnology.com/projects/searose/. 
C-14 

Technip. n.d. Company Web site. Technologies and Products. Flexible standing hybrid riser 

brochure. Available at: http://www.technip.com/pdf/brochures/Brochure_FSHR_09.pdf

U.S. Department of the Interior. Minerals Management Service (USDOI MMS). 2008. 

Deepwater Gulf of Mexico 2008: America’s offshore energy future. OCS Report MMS

2008-013. May. Available at: http://www.gomr.BOEMRE.gov/PDFs/2008/2008-013.pdf. 

U.S. Department of Labor. Bureau of Labor Statistics. (USDOL BLS). 2010. Consumer price 

index. All urban consumers (CPI-U). Available at: 

ftp://ftp.bls.gov/pub/special.requests/cpi/cpiai.txt. 
D-1 

APPE NDIX D. PLATFOR M FAB R ICATION S ITE S

ERG used the OCS-Related Infrastructure in the Gulf of Mexico Fact Book (Louis Berger 

Group 2004) as the starting list of platform fabrication facilities. ERG traced the history of each 

location since 2000 (the date of the data in Louis Berger Group [2004]) to determine 1) whether 

the yard still existed after Hurricanes Katrina, Rita, and Ivan roared through the region; 2) its 

current ownership; and 3) whether it still manufactured oil and gas production platforms. ERG 

searched the Dun & Bradstreet (D&B) Million Dollar Directory and other sources to obtain 

financial data for each location (D&B 2010).33

D.1. ALABAMA

Sections D.1 through D.4 contain the discussions 

for platform fabrication yards in Alabama, Mississippi, Louisiana, and Texas, respectively. 

Section D.5 includes the summary table.

BAE Systems acquired Atlantic Marine Holding Company’s operations in Mississippi (Moss 

Point),34

D.2. MISSISSIPPI

Alabama (Mobile), and Florida (Mayport and Jacksonville [BAE Systems 2010]). 

Atlantic Marine is listed as BAE Systems Southeast Shipyards in the workboat.com directory as 

offering offshore vessel and rig repair and fabrication services. For this reason, ERG retains them 

in the set of fabrication facilities (Workboat 2010). 

D.2.1. Friede Goldman Offshore Gulfport Yards 

Friede Goldman Halter, Inc., went into bankruptcy in 2002. Singapore Technologies (VT 

Halter Marine) acquired the Halter Gulfport and Halter Gulfport Central yards but later resold 

them to Trinity Yachts and Gulf Coast Hatteras, respectively (Colton 2010). Both locations focus 

on yachts, not platform fabrication. Signal International was formed to acquire Friede Goldman 

assets, including the Pascagoula East and West yards (Friede Goldman Halter 2003). 

D.2.2. Ingalls Shipbuilding Yard in Pascagoula

In March 2011, H untington Ingalls was spun off from Northrup Grumman and is thus the 

owner of the Ingalls shipbuilding yard in Pascagoula at the time this report was written. 

Huntington Ingalls identifies itself as a shipbuilding business in its 2011 10k report. There is no 

mention of platform construction for the offshore oil and gas industry (Huntingon Ingalls 2011). 

As a r esult, ERG inferred that this location was unlikely to supply the offshore oil and gas 

industry with platforms and removed it from the list.

D.3. LOUISIANA

D.3.1. Not in Scope

ERG, in consultation with BOEM, eliminated three facilities from the subset of platform 

manufacturers (Mar-Con, Inc; Edison Chouest; and L-Con Marine Fabricators). 

 

33 Because the database was searched in 2010, the revenue and employment data reflect 2009 data. However, it 

is the proportion of revenues generated at each location that is used in the onshore distribution for MAG-PLAN; 

thus, the data are less affected by year-to-year variations in the absolute value of revenues.

34 The Moss Point, Mississippi, facility operates under the name Millennium Industrial and Marine Solutions.
D-2 

D.3.2. Ownership Changes and Name Changes

D.3.2.1. J. Ray McDermott, Inc. in Amelia

Bollinger bought J. Ray’s Amelia Yard in 1997 (Business Wire 1997). 

D.3.2.2. Sigma Industries, Inc. in Houma

The Houma, Louisiana, facility listed as Sigma Industries in Louis Berger Group (2004) is 

indicated as belonging to Chet Morrison Contractors in USEPA (2010b). The Chet Morrison 

Web site lists two locations within Houma, Louisiana, both of which have fabrication facilities 

(Chet Morrison 2010). ERG found D&B data for the Harvey, Louisiana, location (50 employees, 

$5.99 million in revenues). We could find employees for the Houma, Louisiana, location (500 

employees) but not revenues. ERG extrapolated the $0.12 million per employee at the Harvey 

yard to the 500 employees at the Houma yard for an estimated $59.9 million in revenues. ERG 

infers that the D&B record contains the information for both locations. 

D.3.2.3. Gulf Island Fabrication

Gulf Island Fabrication is a publicly owned company. At the end of 2009, the 10-K form 

reported a total of $311.529 million in revenues and 1,400 employees (Gulf Island Fabrication 

2009). The fabrication yards are described as:

• Houma, Louisiana. East side of the Houma Navigation Canal (main fabrication yard and 

corporate headquarters). 

• Houma, Louisiana. West side of the Houma Navigation Canal. 

• Houma, Louisiana. East side of the Houma Navigation Canal, to the north of the main yard 

(formerly known as the Southport facility).

• Houma, Louisiana. Dolphin Services. 

• Ingleside, Texas. Gulf Marine Fabrication. 

• Aransas Pass, Texas. Gulf Marine Fabrication, north yard. 

The D&B directory does not list the Gulf Marine Fabrication locations in the Gulf Island 

Fabrication corporate tree; only Louisiana properties are listed. ERG found one entry for Gulf 

Marine Fabrication with an address of Aransas Pass, but it appears to encompass both the 

Aransas Pass and Ingleside locations. The corporate brochure for Gulf Marine Fabrication shows 

them located near each other. ERG found separate entries in D&B for Dolphin Services and 

Southport Inc. ERG summed the entries for Dolphin, Southport, and Gulf Marine Fabrication. 

The difference between the total revenues for the company and the sum of the revenues at the 

known locations was assigned to the Houma East and West yards. This was also done for 

employment estimates for the Houma East and West yards. The Gulf Marine Fabrication 

facilities were purchased by Gulf Island Fabrication in 2006, and the yard is an addition to the 

Louis Berger Group (2004) list. 

D.3.2.4. Allen Process Systems, Dynamic Industries, and Moreno Energy Group

Allen Process Systems, Dynamic Industries, and Moreno Energy Group have shared a 

complicated history. The Independent Review publishes lists of Acadiana’s top 50 privately held 

companies. The 2010 l ist placed Moreno Group as number 1, with $619 million in 2009 
D-3 

revenues; however, it also describes the Moreno Group as several related businesses, of which 

Dynamic Industries is one. In 2009, D ynamic Industries was listed as number 5, with $313.9 

million in revenues for 2008, having 2,000 employees, located in Iberia Parish, and with Mike 

Moreno as the top executive (The Independent 2009). That is, the $313.9 estimate for the 2008 

revenues is the best estimate that ERG could identify for Dynamic Industries. The D&B database 

lists two locations in Harvey, Louisiana, and one location in each of Broussard, Louisiana; Alvin, 

Texas; and Dumas, Texas. However, the Dumas location is not listed on the Dynamic Industries’ 

Web site as of March 2011; therefore, ERG removed this location (Dynamic Industries 2011). 

ERG lists one location in Harvey, Louisiana, and one in New Iberia, Louisiana, because the 

location with 950 employees has a street address in New Iberia and a mailing address with a P.O. 

Box in Harvey. Dynamic Industries acquired Allen Process Systems in 2006 ( OGJ 2006), 

leading to an expansion of the New Iberia facility. ERG summed the reported revenues for the 

four locations reported in the D&B database. ERG assigned the difference between the $313.9 

million reported for the company and the sum of the revenues for the other locations as the 

revenues for the New Iberia location. 

D.3.2.5. Offshore Specialty Fabricators

Offshore Specialty Fabricators is another company with a h ard-to-determine status.35

As a result of the above research, ERG identified four Offshore International Group 

locations: 

The 

Offshore Specialty Fabricators Web site contains no i nformation regarding further corporate 

ownership. The EPA database has two locations within Houma, Louisiana, for Offshore 

Specialty Fabricators and one for Aransas Pass, Texas. The EPA data lists “Offshore Express” as 

an alternative name for the company (USEPA 2010c). ERG verified Offshore Express as an 

alternative name for Offshore Specialty Fabricators through a search of Ward's Business 

Directory of U.S. Private and Public Companies (Ward 2008). A check of Offshore Seismics’ 

Web site (listed in Ward 2008) mentions that it is part of the Offshore International Group of 

companies. Bloomberg Businessweek company information indicates that Offshore International 

Group is privately held, with subsidiaries in the oil and gas business in the United States and 

Peru (Bloomberg 2010). The Business Monitor International reports that Savia Perú—a joint 

venture formed by Ecopetrol and Korea National Oil Corporation—purchased Oil International 

Group in February 2009 for $900 million (Business Monitor International 2010). The report 

mentions the Peruvian operations as Oil International Group’s main asset. However, it is not 

clear whether Savia Perú purchased all of Offshore International Group (implied by the language 

in Business Monitor International [2010]) or only the Peruvian operations, because Bloomberg 

(2010) reports total sales of $74.5 million for the six-month period ending June 30, 2010. 

• Offshore Specialty Fabricators Inc. in Houma, Louisiana. 

• Offshore Specialty Fabricators Inc. in Houston, Texas. 

• Fairway Offshore Exploration in Houston, Texas (also doing business as Offshore Specialty 

Fabricators Offshore Specialty Fabricators Inc.). 

• Offshore Express Inc. in Aransas Pass/Ingleside, Texas (Offshore Specialty Fabricators Inc.). 

 

35 Dismukes et al. (2003) lists it as Offshore Specialty Fabricators, Inc., while the Web site lists it as a limited 

liability company (LLC).
D-4 

The next step is to generate best estimates of the revenues and employees for each location. 

While the process will not result in precise estimates, the purpose of the estimates is to form a 

proportional basis for allocating platform fabrication expenditures to various locations in the 

GOM. Manta.com reports that 2009 revenues for Offshore Specialty Fabricators are between $50 

million and $100 million and that the company has between 250 and 499 employees. These data

are consistent with the $52.4 million and 300 employees reported for 2004 in Ward’s Business 

Directory (Ward 2004). ERG used the midpoint estimate of $75 m illion in revenues. D&B 

(2010) lists revenues of $1.15 million and $17.5 million for the Offshore Specialty Fabricators 

and Fairway Offshore Exploration locations in Houston, Texas, respectively, while Manta.com 

lists revenues of $5 m illion to $10 m illion for Offshore Express in Aransas Pass/Ingleside, 

Texas. ERG estimated revenues of $49 million for the Houma, Louisiana, location by taking the 

difference between the sum of revenues for all reported locations and total revenues.36

D.3.2.6. UNIFAB International

ERG 

assumes that the six-month earnings of $74.5 million reported in Bloomberg (2010) include 

additional operations such as Offshore Seismic Surveys. 

In March 2005, Midland Fabricators acquired UNIFAB International and took the company 

private (UNIFAB 2005). 

D.3.2.7. Bay Offshore/Berry Contracting

Berry Contracting, L.P., is the parent company for entities known under the names Bay 

Limited and Bay Offshore Limited (Bay Limited 2010; D&B 2010). The company Web site

says it has shops and yards in Corpus Christi, Texas; Morgan City and Belle Chase, Louisiana; 

and the Port of Tampico, Mexico. The Morgan City yards are listed as being in Amelia, 

Louisiana (Bay Limited 2010). 

Louis Berger Group (2004) also listed a Bay Offshore facility in New Iberia, Louisiana, but 

such a location is not mentioned on the company Web site (D&B [2010]) or the EPA database. 

Thus, ERG removed the New Iberia location from the updated list. While there are two locations 

in Amelia, Louisiana, the financial data in D&B (2010) appears to have been presented on a 

combined basis and listed under Morgan City. As a result, we list both yards under one entry in 

the updated list. D&B (2010) had separate listings for the Belle Chasse (Mosby Group), 

Louisiana, and Corpus Christi, Texas, locations. 

D.4. TEXAS

D.4.1. First Wave Newpark Shipbuilding

ERG searched the EPA database and identified three locations for Newpark Shipbuilding in 

Galveston, Texas: Galveston Island, Pelican Island East, and Pelican Island West (USEPA 

2010d). The Galveston Island location has an alternate name of First Wave Marine Inc. in the 

EPA record. ERG examined maps and found that Port Industrial Road merges with Harborside 

Drive and that Bludworth Marine Shipyard has the same street address. Bludworth Marine 

repairs commercial vessels but does not offer platform fabrication. Thus, this location is not in 

scope. 

 

36 ERG used the midpoint estimate of revenues for the Aransas Pass location.
D-5 

The Pelican Island East location has an alternate name of Gulf Copper and Manufacturing 

(USEPA 2010d). Gulf Copper and Manufacturing offers rig repair and retrofitting for jackups 

and semisubmersibles (Gulf Copper and Manufacturing 2010). This location is in scope. 

The Pelican Island West location appears with alternate names of SWSY Holdings, SWSY 

Holdings-Brady Island, and Southwest Shipyard (USEPA 2010d). Southwest Shipyard (Pelican 

Island West) builds and repairs barges (Colton 2010) and is out of scope. 

D.4.2 Brown & Root Greens Bayou

Austin et al. (2008), Colton (2010), and U.S. Army Corps of Engineers (2006) indicate that 

the yard was sold off in pieces in 2004 a nd was still inactive in 2006. Based on t he business 

address of its waterfront location, Spitzer Industries, Inc. appears to have taken over part of the 

property to manufacture subsea equipment (Spitzer 2010). 

D.4.3 Kiewit Offshore Services

In 2001, Peter Kiewit Sons’ built a state-of the art platform fabrication facility in Ingleside, 

Texas (Kiewit 2010). D&B lists 450 employees at this location but does not list revenues. The 

Hoovers.com company profile lists 500 employees and notes that the average annual revenue per 

industry worker is $350,000 (Hoovers 2010). If the facility earned average annual revenues per 

employee, the annual revenues would be calculated as $175 million. However, the D&B family 

tree for Kiewit Offshore Services includes an Omaha, Nebraska, location with revenues of 

$414.8 million. If this revenue number is associated with the 450 e mployees reported for the 

Ingleside location, then the average revenue per employee would be $922,000 or about 2.5 times 

higher than the average. Given that the Kiewit facility was new and state of the art in 2001, ERG 

considered it reasonable to accept the higher revenue per employee value. As a result, Table D-1 

lists 450 employees and $414.8 million in revenues for the Ingleside, Texas facility. 

D.4.4 Aker Gulf Marine

D&B lists 1,130 employees for the Aker Gulf Marine Ingleside, Texas yard but does not list 

revenues. In the absence of more definite information, ERG imputed the revenues based on the 

average annual revenue per employee of $350,000 reported in Hoovers (2010). The Aker Marine 

facility has imputed revenues of $396 million.

D.5 SUMMARY

The offshore platform fabrication industry supported more than 23,000 jobs in 2009 a nd 

represents approximately $3.7 billion in revenues (see Table D-1).
D-6 

Table D-1 

Summary of Platform Fabrication Facilities

Name Current Owner Former Owner City State County

2009 

Revenues 

(Millions)

Employment

Mobile Yard BAE Systems

Atlantic Marine Holding 

Company Mobile AL Mobile $35.16 500

Alabama Total $35.16 500

New Iberia Yard Cameron International Corp Natco New Iberia LA Iberia $21.18 100

New Iberia Yard Dynamic Industries, Inc. New Iberia LA Iberia $279.04 950

New Iberia Yard Marine Industrial Fabrication Unifab International, LLC New Iberia LA Iberia $32.00 120

New Iberia Yard Omega Natchiq/ASRC Omega Service Industries, Inc. New Iberia LA Iberia $67.00 475

Delcambre Yard Shaw Group (Shaw Bagwell) Delcambre LA Iberia $34.53 300

Harvey Yard Anders Construction Harvey LA Jefferson $0.25 3

Harvey Yard Chet Morrison Contractors, Inc. Harvey LA Jefferson $5.99 50

Harvey Yard Dynamic Industries, Inc. Harvey LA Jefferson $18.81 250

Harvey Yard Houma Industries Harvey LA Jefferson $16.10 176

Dynamic Industries, Inc. Broussard LA Lafayette $9.40 75

Harvey Yard

Production Mgmt Industries 

(PMI)

Golden 

Meadow LA Lafourche $0.60 4 

Mosby Unit Berry Contracting, LP Bay Offshore Ltd. Mosby Unit Belle Chasse LA Plaquemines $0.13 3

Belle Chasse 

Yard Omega Service Industries, Inc. Belle Chasse LA Plaquemines $67.00 475

East/West/North 

Yards Berry Contracting, LP Bay Offshore Ltd. Amelia LA Saint Mary $54.57 200

Amelia Yard Bollinger Shipyards J. Ray McDermott, Inc. Amelia LA Saint Mary $42.99 396

J. Ray McDermott Morgan City LA Saint Mary $15.07 100

Baldwin Yard Superior Fabricators, Inc. Baldwin LA Saint Mary $4.60 40

South Louisa 

Yard Twin Brothers Marine Morgan City LA Saint Mary $14.62 202

Houma Yard Chet Morrison Contractors, Inc. Houma LA Terrebonne $59.90 500

Houma Yard Dolphin Services, Inc. Houma LA Terrebonne $29.80 249

Houma Yard Gulf Island Fabrication, Inc. Southport, Inc. Houma LA Terrebonne $33.00 200

Houma Yard Gulf Island Fabrication, Inc. Houma LA Terrebonne $206.83 351
D-7 

Table D-1. Summary of Platform Fabrication Facilities (continued)

Name Current Owner Former Owner City State County

2009 

Revenues 

(Millions)

Employment

Gibson Yard Max Welders, Inc. Gibson LA Terrebonne $8.90 90

Houma Yard

Offshore Specialty Fabricators, 

Inc. Houma LA Terrebonne $49.00 150

Abbeville Yard Acadian Contractors Abbeville LA Vermilion $16.30 300

Abbeville (Port 

of Vermillion) 

Yard Gulf Coast Marine Fabricators Abbeville LA Vermilion $15.75 45

Louisiana Total $1,103.36 5,804

Pascagoula East 

Yard Signal International Friede Goldman Offshore Pascagoula MS Jackson $398.00 1,400

Pascagoula West 

Yard Signal International Friede Goldman Offshore Pascagoula MS Jackson 

LeTourneau Technologies Vicksburg MS Warren $249.06 850

Mississippi Total $647.06 2,250

Dynamic Industries, Inc. Alvin TX Brazoria $5.24 30

Brownsville Yard Keppel Amfels, Inc Brownsville TX Cameron $270.50 1,528

Pelican Island 

East Gulf Copper & Manufacturing

Newpark Shipbuilding Pelican 

Island East Galveston TX Galveston $4.50 5

Channelview 

Yard Delcor Delta Engineering Corporation Channelview TX Harris $37.80 250

Fairways Offshore Exploration

aka Offshore Specialty 

Fabricators, Inc. Houston TX Harris $17.47 22

Offshore Specialty Fabricators, 

Inc. Houston TX Harris $1.15 10

Seahorse Platform Houston TX Harris $0.10 2

Turbofab Facility Solar Turbine Inc. Channelview TX Harris $35.03 200

Greens Bayou 

Yard Spitzer Industries Brown & Root Greens Bayou Houston TX Harris $206.87 505

Signal International Port Arthur TX Jefferson $8.68 80

United Marine Shipyard Port Arthur TX Jefferson $11.20 252

Berry Contracting, LP Corpus Christi TX Nueces $420.62 850

Signal International Orange TX Orange $29.30 305
D-8 

Table D-1. 

Summary of Platform Fabrication Facilities (continued)

Source: D&B (2011) for revenues and employment data; see text for details for specific locations. 

Name Owner Former Owner City State County

2009 

Revenues 

(Millions)

Employment

Ingleside Yard Aker Gulf Marine Ingleside TX San Patricio $395.50 1,130

Ingleside Yard Gulf Marine Fabricators Ingleside TX San Patricio $41.90 600

Kiewit Offshore Ingleside TX San Patricio $414.80 450

Ingleside Yard

Offshore Specialty Fabricators, 

Inc. Aransas Pass TX San Patricio $1.15 10

Ingleside Yard State Service Co., Inc. Ingleside TX San Patricio $42.19 93

Texas Total $1,944.00 6,322

Grand Total $3,729.59 23,430
D-9 

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D-10 

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D-11 

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http://www.theind.com/business-cover/6656-cover-story-julyaugust-2010 and 

http://www.theind.com/images/stories/07.28.2010/ABIZ.list17-18.pdf. 

UNIFAB. 2005. UNIFAB International. Form 8-k. Available at:

http://www.sec.gov/Archives/edgar/data/101990/000095012905003100/h24000e8vk.htm. 

U.S. Army Corps of Engineers. 2006. US Army Corps of Engineers. New Orleans District. 

Mississippi Valley Division. Port of Iberia, Louisiana. Final feasibility report. Volume 2: 

Appendix A – Economics. October 2006. Available at: 

http://www.mvn.usace.army.mil/pd/projectslist/ProjectData/108797/reports/POI%20Vol%20

2%20%20App%20A%20Econ%20Oct%2006.pdf. 

U.S. Environmental Protection Agency (USEPA) 2010a. Envirofacts, MultiSystem search. 

Facility registry system, facility detail report. Mar-Con, Inc. Available at:

http://www.epa.gov/enviro/facts/multisystem.html. 

U.S. Environmental Protection Agency (USEPA). 2010b. USEPA, Envirofacts, Facility registry 

system, facility detail report, Chet Morrison Houma, LA record Available at:

http://www.epa.gov/enviro/facts/multisystem.html. 

U.S. Environmental Protection Agency (USEPA). 2010c .USEPA, Envirofacts, offshore 

specialty fabricators. Available at: http://www.epa.gov/enviro/facts/multisystem.html. 

U.S. Environmental Protection Agency (USEPA). 2010d.USEPA, Envirofacts, Newpark 

Shipbuilding Galveston Island, Pelican Island East, and Pelican Island West. Available at: 

http://www.epa.gov/enviro/facts/multisystem.html. 

Ward's Business Directory of U.S. 2008. Private and public companies, 51st ed., 2008 available 

through Gale Directory Library. 

Ward's Business Directory of U.S. 2004. Private and public companies, 47th ed., 2004 available 

through Gale Directory Library. 

Workboat. 2010. Directory. Entry for BAE Systems (Atlantic Marine). Available at:

http://www.workboat.com/directory.company.details.aspx?id=4294977517&b=1349. 
E-1 

APPE NDIX E . S E MIS UB ME R S IB LE S TR UCTUR E COSTS

ERG examined the total and component costs for semisubmersible structures in the GOM, as 

well as where the components were manufactured. This was done to estimate the proportion of 

the expenditures that flow outside the United States. 

E.1 DESCRIPTION

A semisubmersible is a type of floating production system. Semisubmersibles’ working 

decks are supported by columns on hul ls or pontoons. Depending on t he design, it might be 

towed or moved to the drill site under its own power. When on location, the hulls or pontoons are 

flooded such that most of the mass of the structure lies below the water surface. Because of this, 

the structure shows little front-to-back or side-to-side rolling or pitching. The up-and-down 

motion still continues, but this is addressed by the riser system. The production structures 

typically are anchored or use dynamic positioning to stay in place. 

E.2 TYPICAL COSTS

ERG identified a set of seven semisubmersible production structures in the GOM from the 

2008 worldwide survey of semisubmersible floating production systems and units (Wilhoit and 

Supan 2008).37,38

Where possible, we identified total cost as well as separate costs for the hull, topsides, 

integration, conversion, and installation. This means that the sum of the individual entries might 

not equal the total cost. In one case, we had total cost and individual costs for all but one 

category and used the difference between total cost and the sum of the individual costs to impute 

the value for the missing component. These are shown in bold italic font in Table E-1. 

Table E-1 lists the water depth, first production date, and date of the reported 

cost information. 

Collecting cost information is not straightforward. Even when ERG found a cost, some of the 

remaining questions were:

• Is this the total project cost or only the company’s share? 

• Does the cost cover one or more than one project? 

• What is included in the costs (e.g., hull, topsides, integration, installation)? 

• Does it include the cost for drilling the wells associated with the production structure?

We discuss each structure separately along with the assumptions ERG made in interpreting 

the data. None of the references provide a cost estimate with a base year for the dollars. ERG 

thus assumes the value is in current dollars and the date of the publication is used as the date for 

the dollars. 

E.2.1 Atlantis 

For the Atlantis semisubmersible located on Green Canyon 787, ERG found two estimates 

for total project cost—$3.7 billion and $2 billion. Although the estimates differ by a factor of 

 

37 The Helix Producer 1 is listed on the poster; however, it was converted from a train ferry to a ship-shape 

floating production unit (CSC n.d.). ERG determined it was different enough from the semisubmersible vessels to 

exclude from the analysis.

38 ERG found the semisubmersible that produces from the Gomez field listed as “Gomez” in Nixon et al. (2009) 

and as “Innovator” in ATP reports.
E-2 

two, the magnitude of the difference between the two would result in substantial differences in 

the socioeconomic impacts estimated in MAG-PLAN. JPT Online (2007) and Macdonald-Smith 

and Gismatulin (2007) provide the total cost of $3.7 billion, with BP being the majority owner at 

56 percent (JPT 2007). BP’s share would come to an estimated $2.07 billion. J. Ray McDermott 

(2008) and SubseaIQ (2010) list the project cost at $2 billion. However, ERG found references 

for parts of the work where the total exceeded $2 billion, so Table E-1 lists $3.7 billion as the 

total cost.

ERG could not locate the estimated cost for the hull constructed at the Daewoo Shipbuilding 

and Marine Engineering (DSME) shipyard in Korea. Offshore (2003) and SubseaIQ (2010) 

report that J. Ray McDermott got a $600 million contract to construct the topsides. SubseaIQ 

(2010) notes that Heerema Marine was awarded a $400 million contract for the installation and 

associated pipelines and gathering lines, and Subsea 7 was awarded a $30 million contract for the 

installation of 26 miles of umbilicals. This is the $430 million entry for installation in Table E-1. 

Bardex Corporation and FMC Technologies were awarded contracts for unspecified amounts for 

the mooring systems and subsea trees, manifolds and connection systems (SubseaIQ 2010). 

Beshur (2005) discusses the work assembling the hull and topsides at the Kiewit shipyard. It 

mentions that the project will involve more than 1,000 workers and cost more than $1 billion. 

Beshur (2005) reports on local business for the Corpus Christi Caller Times. J. Ray McDermott 

(2008) mentions that the integration of the topsides and hull would take place in Corpus Christi 

facilities but does not specify the contractor or contract value. As a result, ERG estimates the 

integration work to be $1 billion in Table E-1. Thus, ERG could find estimates totaling $2.4 

billion before hull, mooring system, subsea trees, manifolds, and connection system costs are 

included. 
E-3 

Table E-1 

Semisubmersible Costs

Facility Name Atlantis

Independence 

Hub

Innovator/ 

Gomez Na Kika Blind Faith

Thunder 

Hawk

Thunder 

Horse Average

Water Depth (ft) 7,072 7,918 2,998 3,070 6,494 5,707 6,065

First Production Date 2007 2007 2006 2004 2008 2009 2008

Cost Date 2005 2006 2005 2001 2008 2009 2008

CURRENT DOLLARS (millions)

Hull Cost $50 $50 $120 $380

Topsides Cost $600 $396 $625 $720 $600

Integration Cost $1,000 $25 $303

Conversion Cost $30

Installation Cost $430 $635 $35 $23 $30

Total, as reported $3,700 $2,000 $80 $1,260 $900 $326 $5,000

2008$ (millions)

Hull Cost $53 $55 $120 $380 $152

Topsides Cost $661 $423 $760 $720 $600 $633

Integration Cost $1,102 $28 $302 $477

Conversion Cost $33

Installation Cost $474 $772 $35 $23 $30 $267

Total, as reported $4,077 $2,136 $88 $1,532 $900 $325 $5,000 $2,008

Note: Total costs and component costs identified separately; thus, the sum of component costs may not equal the total reported cost.

Source: JPT (2007); Macdonald-Smith and Gismatulin (2007); SubseaIQ (2010); Enterprise (2006); Alexander’s Gas & Oil Connections (2006); ATP 

2005; USDOI MMS (2004); McCaul 2001; energyme.com (2005); Solholm (2005); Rigzone (2005); Kiewit (2008); SBM 2009a; Upstream (2007); Magers 

(2005) and Lang (2008).
E-4 

E.2.2 Independence Hub

Teasing apart the semisubmersible costs for Independence Hub introduces a different set of 

complications. First, the Independence Project consists of a semisubmersible production 

structure (Independence Hub), a pipeline tying the structure to onshore facilities (Independence 

Trail), and the subsea connections from the gas fields to the structure (Independence Subsea). 

Second, an energy company—Enterprise Products Partners, L.P.—is the majority owner (80

percent) of Independence Hub and owner of the Independence Trail (100 percent), while five 

independent exploration and production companies39 own their respective portions of the subsea 

completions and flow lines tying six gas fields to Independence Hub (Enterprise n.d.; 

Alexander’s Gas & Oil Connections 2006; Anadarko 2008).40

Enterprise (n.d.), Alexander’s Gas & Oil Connections (2006), and SubseaIQ (2010) report 

total costs for the project as $2 billion. The $50 million cost estimate for Independence Hub’s 

hull is from the Jurong shipyard’s announcement of the contract award (SembCorp 2005). 

As a result, ERG sometimes needs 

to ascertain whether cost information presented by Enterprise Products Partners, L.P represents 

the semisubmersible structure, pipeline, or both, or whether costs reported for the Independence 

Project include the subseabed completions. 

Anadarko (2004), Offshore (2005), and USDOI MMS (n.d.) say the Independence Hub 

structure is estimated to cost $385 million. Anadarko (2008) mentions that Enterprise GP 

Holdings invested more than $650 m illion to design, construct, and install the structure and 

associated pipeline, which could be consistent with a $385 million structure and $281 million 

pipeline. Enterprise (2006), however, states that the platform and pipeline costs are estimated at 

$445.9 million and $281.3 m illion, respectively. ERG considers that the semisubmersible 

structure cost total of $446 million is more accurate and that it in cludes the hull cost.41

At this point, ERG has identified only $446 million in costs for a $2 billion project. A clue 

for the other expenditures might be found in Anadarko (2006), where the company announced a 

capital budget of $4 billion. Twenty-three percent of the budget (or approximately $920 million) 

is allocated to the deepwater GOM. Furthermore, Anadarko mentions that about 10 percent

(about $400 million) of the total budget will go toward installing facilities that link the Anadarko 

gas fields to Independence Hub.

As a 

result, Table E-1 shows the $50 m illion for the hull and the remaining $396 m illion for the 

topsides and installation

42

 

39 Anadarko Petroleum Corp., Dominion Exploration & Production Inc., Kerr-McGee Oil & Gas Corp., 

Spinnaker Exploration Co., and Devon Energy Corp., also referred to as the Atwater Valley Producers Group. 

Given that there are four other companies linking up t o 

Independence Hub, one possible interpretation is that the $1.5 billion “gap” represents the 

expenditures by the oil and gas companies to develop and link their remote gas fields to 

Independence Hub.

40 The companies get access to gas processing capacity, pay a monthly fee (regardless of capacity used), and pay 

a processing fee dependent on the capacity used. 41 ERG considers the value published in a 10-K form filed with the Securities and Exchange Commission in 

2006 to be of higher data quality than a value published in a 2005 industry magazine. 42 Another 10 percent is spent to bring six wells online at the Marco Polo hub facility. That is, Anadarko is 

spending its 2006 capital budget for the GOM on Independence Hub and Marco Polo.
E-5 

E.2.3 Innovator/Gomez

ATP Oil and Gas decided to develop a marginal gas field in Mississippi Canyon block 711 

using a converted semisubmersible drilling unit rather than building a new facility (Paganie 

2006). ATP purchased the Rowan Midland from Rowan for a price of $50 million (ATP 2005) 

and renamed it the ATP Innovator (ATP 2006). The semisubmersible was converted at Signal 

International’s Port Arthur, Texas, yard. Omega Services of New Iberia, Louisiana, supplied the 

process modules, and Intermoor supplied the mooring system of polyester rope attached to the 

seabed via suction-embedded plate anchors (SEPLAs). Innovator marked the first floating 

production system to use SEPLA anchors in the GOM (Paganie 2006 and Signal 2010).43

SubseaIQ (2010) lists the development cost for the production facility as $80 million.44

E.2.4 Na Kika

ERG 

assumes that this represents the $50 million purchase price for the Rowan Midland plus the cost 

to convert and install the structure (i.e., contracts to Omega Services and Intermoor). 

The total cost for Na Kika is $1.26 bi llion (USDOI MMS 2004, McCaul 2001). McCaul 

(2001, 2003) provides a further breakdown: 

• $625 million for fabrication and installation of the production structure and pipeline 

• $317.5 million for fabrication and installation of the subsea components 

• $317.5 million for drilling and completion of wells 

That is, roughly half for the structure and pipeline and one-quarter each for the subsea 

components and wells. 

E.2.5 Blind Faith

The total capital cost for the development of Blind Faith is estimated at $900 million by 

SubseaIQ (2010). ERG found cost estimates for the hull, installation, and integration; Aver 

Kvaener was awarded a contract for the hull and installation at $120 m illion and $35 m illion 

(SubseaIQ 2010, e nergyme.com 2005, S olholm 2005, R igzone 2005), respectively, and $25 

million was contracted to Kiewit for the integration (Kiewit 2008). The topsides were fabricated

by Gulf Island LLC, a wholly owned subsidiary of Gulf Island Fabrication, but ERG was unable 

to find the cost of the contract (Gulf Island 2005). ERG estimated the cost to be $720 million 

because it is the only missing component of the total $900 million capital cost. Blind Faith is 

primarily held by Chevron, with a 62.5 percent interest, and Kerr-McGee holds the remaining 

interest.

 

43 The poster compiled by Wilhoit and Supan (2008) lists the fabrication yard as Levingston Shipyard and 

Rowan Companies as the Conversion/Integration Yard. Signal (2010) lists the conversion work as occurring in their 

Texas shipyard. 44 Paganie (2006) says the total capital expenditures associated with acquisition, conversion, and other expenses 

totaled about $100 million. However, Paganie (2006) also states the acquisition price for Rowan Midland as $60 

million, when ATP reports the cost as $50 million (ATP 2005). Because the structure cost in Paganie 2006 is high 

compared to what is reported by ATP, ERG chose to use the SubseaIQ estimate of $80 million for the total cost.
E-6 

E.2.6 Thunder Hawk 

Thunder Hawk commenced first production in July 2009. The semisubmersible was built and 

is owned by SBM Offshore, a Dutch holding company. Murphy Oil operates the unit, and all 

users pay a day rate and some value of production to SBM Offshore. (See Independence Hub, 

Section E.2.2 for a description of a similar financial arrangement.) ERG had difficulty finding 

cost information for this unit. SBM Offshore announced the lease order for the Thunder Hawk 

semisubmersible in a news release that also included a mobile production unit with storage for 

Yme, North Sea; turnkey orders for three semisubmersible drilling units; and orders for drilling 

units and process modules. The total value of the orders was $1.2 billion (SBM 2006), but only a 

fraction of that is attributable to Thunder Hawk. ERG found an entry in the 2009 SBM Offshore 

annual report listing an outstanding loan balance of $303 m illion for Thunder Hawk (SBM 

2009a). This is likely to be a low estimate because it includes only what SBM offshore financed 

through long-term debt. It does not include any part of SBM Offshore’s revolving debt or 

capitalized/expenses interest payments. However, the $303 million estimate, while low, appears 

credible. SBM Offshore’s brochure on semisubmersible production units mentions that Thunder 

Hawk is a near-clone of Independence Hub but is meeting updated design requirements (SBM 

2009b). The $303 million estimate for Thunder Hawk is similar to the $396 million estimate for 

Independence Hub.

The only other cost component for which ERG could find an estimate was for installing the 

mooring system, transport, and hook-up of the facility. Aker Kvaerner won the $23 m illion 

contract (Upstream 2007). 

E.2.7 Thunder Horse

The Thunder Horse field was discovered in 1999, but it took 10 years to become the 

extremely productive field it currently is (Knott 2009). Given the water depth (6,050 feet), 

reservoir depth (between 14,000 to 19,000 feet below the seabed), and reservoir temperature and 

pressure (between 13,000 to 18,000 ps i and between 190 t o 270°F), developing the Thunder 

Horse field would take a number of new 

technologies (Knott 2004). 

BP decided to develop the field with a 

semisubmersible production unit, also called 

Thunder Horse. When it was built in 2004–2005, 

it was the largest semisubmersible unit in the 

world, with a height of about 450 f eet from the 

base of the hull to the top of the drill rig and a 

deck area of about 3 acres (USDOI MMS 2005 

and Figure E-1). It was originally scheduled for 

installation in 2005; however, as sometimes 

happens with cutting-edge projects, some 

difficulties cropped up along the way to first 

production. Thunder Horse was towed to its 

production site in April 2005. Hurricane Dennis blew through in early July 2005 and afterward, 

the unit was tilted to about 20 to 30 degrees. The cause of the tilting was not the hurricane but 

rather faults in the ballast/bilge water hydraulic control systems. The remedial work was 

Figure E-1. Thunder Horse

Source: ©BP
E-7 

extensive and took about a year to complete. In mid-2006, when the unit was scheduled to go 

into production, BP found faulty welds in the subseabed manifolds due to unforeseen chemical 

interactions and metal embrittlement. To fix the damage, BP had to retrieve the subseabed 

equipment, refurbish it, and return it to the seabed. Two more steps were necessary for successful 

completions: 1) the development of a nitrogen gas cap in the annulus to absorb the effects of 

packer fluid expansion and 2) contracting and reducing the variability in the copper plating on 

the connection threads.45

ERG considers the story of bringing Thunder Horse into production to explain the two total 

cost estimates it f ound in the literature. Knott (2001) and Tyson (2008) mention that the 

production facility cost more than $1 billion. SubseaIQ (2010) reports that Subsea 7 got a $30 

million contract to install 37 miles of umbilicals and subsea structures. Bradbury (2002) says that 

Daewoo Shipbuilding and Marine Engineering got a $380 m illion contract to build the 

semisubmersible hull, and that J. Ray McDermott “has dedicated its whole site to build process 

topsides modules for the Thunder Horse PDQ [production, drilling, and quarters] and for the 

three spars for Atlantis, Holstein, and Mad Dog in a $600 million deal.” Thus, an upper bound 

estimate for the Thunder Horse topsides is $600 million. These three cost pieces (hull, topsides, 

and subsea) sum to $1.01 billion, which is consistent with Knott (2001) and Tyson (2008). 

Thunder Horse came onstream in June 2008 (Knott 2009). BP notes that 

nearly 14 million man-hours have been expended on t he project since Thunder Horse went 

offshore in 2005 (Knott 2009). 

Two references (Magers 2005 and Lang 2008), however, describe Thunder Horse as about a 

$5 billion investment. Given the 14 m illion man-hours and the analyses, rebuilding, and reequipping needed to get Thunder Horse into production, ERG considers $5 billion to be a more 

likely estimate of the total cost by 2008.

E.2.8 Cost Summary

The estimated semisubmersible costs in 2008$ range from a low of $88 m illion for 

Innovator, which was converted from an existing vessel, to $5 billion for Thunder Horse (see 

Table E-1). Average component costs are calculated on a r ow basis (where the divisor is the 

number of entries with data), so the sum of the average costs for the hull, topsides, integration, 

conversion, and installation does not equal the average total cost. 

E.3 MANUFACTURING LOCATIONS

Table E-2 provides more detail on e ach of the semisubmersible structures in Table E-1, 

including where the different major components were manufactured. The following companies 

built the hulls:

• DSME (Daewoo Shipbuilding and Marine Engineering, Korea) 

• Jurong Shipyard, Singapore 

• Signal International, Texas

• HHI (Hyundai Heavy Industries-Korea)

• Aker Verdal (Norway)

• Dyna-Mac Engineering Services (Singapore)

 

45 Variability in the deposition of copper plating can induce hydrogen atoms in the connection threads. This 

leads to metal embrittlement and potential failure (Knott 2009).
E-8 

For the new-build vessels, the hull is consistently manufactured at foreign locations. Topside 

manufacturing and the integration of the pieces, for the most part, happen at GOM locations. The 

exception is Na Kika, where everything was done in Korea. The work for the sole example of a 

conversion took place in the GOM region. Given the average cost data in Table E-1, 

approximately 7.5 percent of a semisubmersible’s cost is spent overseas on hull manufacture. 
E-9

Table E-2 

Semisubmersible Manufacturing Locations

Facility Name Atlantis Independence Hub

Innovator/

Gomez Na Kika Blind Faith Thunder Hawk

Thunder 

Horse

Vessel Owner BP & BHP

Enterprise & 

Helix Energy 

Solutions

ATP Shell Chevron SBM Offshore BP & Exxon 

Mobile

Vessel Operator BP Anadarko ATP BP Chevron Murphy BP

Field Operator BP Anadarko ATP Shell Chevron Murphy BP

Field(s) Green Canyon 

787

Atlas, Atlas NW, 

Cheyenne, 

Jubilee, 

Merganser, 

Mondo NW, Q, 

San Jacinto, 

Spiderman and 

Vortex

Mississippi 

Canyon 711

Kepler, Ariel, E 

Anstey, Hershel, 

Fourier and 

Coloumb

Mississippi 

Canyon 650, 

695 & 696

Mississippi 

Canyon 736

Mississippi 

Canyon 778

Water Depth (ft) 7072 7918 2998 3070 6494 5707 6065

Year, First Production 2007 2007 2006 2003 2008 2009 2008

Wells, Total 22 16 6 12 5 4 25

Wells, Producing 16 16 6 12

Subsea (Y/N) Y Y Y Y Y Y Y 

Fabrication Yard, Hull DSME Jurong HHI Aker Verdal Dyna-Mac DSME

Fabrication Yard, 

Topside

J Ray 

McDermott Kiewit HHI Gulf Island Kiewit Offshore J Ray 

McDermott

Conversion/Integration 

Yard Kiewit Kiewit Signal 

International HHI Kiewit Kiewit Offshore Kiewit 

General Contractor BP Enterprise Rowan Shell E & P Aker 

Solutions SBM Atlantia

Capacity, oil MBOPD 200 0 20 110 45 60 250

Capacity, gas MMscfd 180 1000 100 425 45 70 200

Quarters Capacity 100 16 98 60 na 38 188

Source: Wilhoit and Supan 2008; Signal 2010
E-10 

E.4 LITERATURE CITED

Alexander’s Gas & Oil Connections. 2006. Company News: North America. Independence 

Project a blueprint for future deepwater exploration. November 9. Available at:

http://www.gasandoil.com/goc/company/cnn64517.htm. 

Anadarko Petroleum Corporation. 2004. News Release. Enterprise and Atwater Valley producers 

group complete agreements for deepwater platform and gas pipeline November 10. Available 

at: http://www.anadarko.com/Investor/Pages/NewsReleases/NewsReleases.aspx?releaseid=642680. 

Anadarko Petroleum Corporation. 2006. News release. Anadarko announces 2006 budget. 

http://www.anadarko.com/Investor/Pages/NewsReleases/NewsReleases.aspx?releaseid=813269 

Anadarko Petroleum Corporation. 2008. News release. Independence project recognized for 

innovation and collaboration. February 14. Available at:

http://www.anadarko.com/Investor/Pages/NewsReleases/NewsReleases.aspx?releaseid=1108627. 

ATP Oil & Gas Corporation. 2005. Form 10-K for year ended December 31. Available at:

http://www.sec.gov. 

ATP Oil & Gas Corporation. 2006. Form 10-K for year ended December 31. Available at:

http://www.sec.gov. 

Beshur, A. 2005. Kiewit dives into Atlantis project. Corpus Christi Caller Times. June 2. 

Available at: http://m.caller.com/news/2005/jun/02/kiewit-dives-into-atlantis-project/, 

accessed 28 September 2009. 

Bradbury, J. 2002. Thunder Horse barrels ahead. E&P. October 1. Available at:

http://www.epmag.com/archives/offshoreReport/3118.htm. 

Croatian Shipbuilding Corporation. n.d. Company Web site. Conversions. Available at:

http://www.hb.hr/download/conversions.pdf

Energyme.com. 2005. Energy News. “Aver Kvaener strengthens position in deepwater 

installation market.” Available at: http://www.energyme.com/energy/2005/en_05_1411.htm. 

Enterprise Products Partners, L.P. n.d. Independence Hub.” Factsheet. (no date) Available at: 

http://www.eprod.com/PDF/Independence%20Hub%20Factsheet%20101206.pdf, accessed 

28 September 2009. 

Enterprise Products Partners, L. P. 2006. Form 10-K For the fiscal year ended December 31, 

2006. Available at: http://www.sec.gov. 
E-11 

Gulf Island Fabrication, Inc. 2005. Company Web site. News Release. “Gulf Island Fabrication, 

Inc. signs agreement to construct topsides for Blind Faith Project. November 4. Available at:

http://www.gulfisland.com/pdf/2005-11-04-Press_Release_Chevron_Blind_Faith.pdf. 

JPT Online. 2007. Journal of the Society of Petroleum Engineers Online. BP’s Atlantis platform 

fully commissioned. December 17. Available at: http://www.spe.org/jpt/2007/12/bps-atlantisplatform-fully-commissioned/. 

Kiewet Corporation. 2008. Company Web site. “Blind Faith Integration-Ingleside, TX.” 

Kiewet.com, 2008. Available at: http://www.kiewit.com/projects/oil-and-gas/blind-faithintegration.aspx, accessed 29 September 2009. 

Knott, T. 2001. Deep Thinking. Frontiers. (BP magazine) September:7-12. Available at:

http://www.bp.com/liveassets/bp_internet/globalbp/STAGING/global_assets/downloads/F/Fr

ontiers_magazine_issue_1_Deep_thinking.pdf. 

Knott, T. 2004. Thunderous Innovation. Frontiers. (BP magazine) August:7–11. Available at:

http://www.bp.com/genericarticle.do?categoryId=9013613&contentId=7021462. 

Knott, T. 2009. Deepwater Horse Power. Frontiers. (BP magazine) August:17–27. Available at:

http://www.bp.com/sectiongenericarticle.do?categoryId=9030433&contentId=7055435. 

Lang, C. 2008. BP Thunder Horse. Available at: http://www.oilrigphotos.com/picture/number103.asp [Note the contributor is listed as “BP” and comments by 

Craig Lang].

Lindsey Wilhoit and Chad Supan, Mustang Engineering. 2008 Worldwide Survey of Semi-FPSs 

and FPUs (excluding FPSOs, SPARs, TLPs). Poster. Available at:

http://downloads.pennnet.com/os/posters/os2008_sfpv.pdf (16 meg).

Magers, P. 2005.Analysis: Giant rig offers new technology. UPI. February 25. Available at:

http://www.upi.com/Business_News/Security-Industry/2005/02/28/Analysis-Giant-rigoffers-new-technology/UPI-63501109635214/. 

McCaul, J. 2001. Floating production systems: Deepwater remote fields rely on floating 

production systems. Oil & Gas Journal 99, Jun 11. 

McCaul, J. 2003. Outlook for floating production systems. Maritime Reporter. August. Available 

at: http://www.imastudies.com/id134.htm. 

Macdonald-Smith, A. and E. Gismatulin. 2007. BP, BHP start pumping at Atlantis Field in U.S. 

Gulf. October 10. Available at:

http://www.bloomberg.com/apps/news?pid=20670001&sid=aATMaWn5HYS4. 
E-12 

J. Ray McDermott. 2008. J Ray McDermott: Morgan City Fabrication. “Atlantis Panoramas.” 27 

June 2008. Available at: http://www.jraymcdermott.com/mcy/mcy_panoramas.htm, accessed 

28 September 2009. 

Offshore. 2003. Offshore Magazine 63(4). New vessels, rigs, upgrades. April 1. Available at:

http://www.offshore-mag.com/index/article-display/173862/s-articles/s-offshore/s-volume63/s-issue-4/s-departments/s-vessels-rigsupgrade/s-new-vessels-rigs-upgrades.html. 

Offshore. 2005. Offshore Magazine 65(1). Independence Hub dependent on six companies. 

January 1. Available at: http://www.offshore-mag.com/index/article-display/220019/sarticles/s-offshore/s-volume-65/s-issue-1/s-departments/s-gulf-of-mexico/s-independencehub-dependent-on-six-companies.html, accessed 5 October 2009. 

Paganie, D. 2006. Independent takes unconventional approach to hub-and-spoke solution. 

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eb.pdf
The Department of the Interior Mission

As the Nation’s principal conservation agency, the Department of the Interior has 

responsibility for most of our nationally owned public lands and natural 

resources. This includes fostering the sound use of our land and water 

resources, protecting our fish, wildlife and biological diversity; preserving the 

environmental and cultural values of our national parks and historical places; and 

providing for the enjoyment of life through outdoor recreation. The Department 

assesses our energy and mineral resources and works to ensure that their 

development is in the best interests of all our people by encouraging stewardship 

and citizen participation in their care. The Department also has a major 

responsibility for American Indian reservation communities and for people who 

live in island communities.

The Bureau of Ocean Energy Management

The Bureau of Ocean Energy Management (BOEM) works to manage the 

exploration and development of the nation's offshore resources in a way that 

appropriately balances economic development, energy independence, and 

environmental protection through oil and gas leases, renewable energy 

development and environmental reviews and studies.