Technical Report No. 164 OCS Study MMS

2002 – 066

Arctic Economic Impact Model for

Petroleum Activities in Alaska

(Arctic IMPAK)

Final Technical Report

 
Technical Report No. 164 OCS Study MMS

2002-066

Final Technical Report

Arctic Economic Impact Model for Petroleum Activities in Alaska (Arctic IMPAK)

Prepared for:

U.S. Department of Interior

Minerals Management Service

Alaska Region

949 E. 36th Avenue

Anchorage, Alaska 99508

Prepared by:

Jack Faucett Associates, Inc

4550 Montgomery Avenue, Suite 300 North

Bethesda, Maryland 20814

In association with

Mr. John Schwochert

Great Northern Engineering

December 2002
This report has been reviewed by the Minerals Management Service and approved for

publication. Approval does not signify that the contents necessarily reflect the view or policies

of the Service, nor does mention of trade names or commercial products constitute endorsement

or recommendations for use. The United States government assumes no liability for its contents

or use thereof.

The study was funded by the Minerals Management Service, U.S. Department of the Interior,

Washington, D.C. under Contract Number 01-98-CT-30907 and Purchase Order Number 01-02-

PO-85307.

Document is available to the public through the National Technical Information Service, 5285 

Port Royal Road, Springfield, Virginia 22161, Fax: 703-605-6900, www.ntis.gov
STUDY TITLE: Update of Oil Industry Labor Factors for Alaska Manpower Model

REPORT TITLE: Arctic Economic Impact Model for Petroleum Activities in Alaska (Arctic

IMPAK)

CONTRACT NUMBERS: Contract Number 01-98-CT-30907

Purchase Order Number 01-02-PO-85307

SPONSORING OCS REGION: Alaska

APPLICABLE PLANNING AREAS: Beaufort Sea, Chukchi Sea, Hope Basin

FISCAL YEARS OF PRODUCT FUNDING: FY 1998 and 2002

COMPLETION DATE OF REPORT: December 2002

COST: FY 1998 $131,503

FY 2000 $11,676

FY 2001 $39,481

FY 2002 $35,108

CUMULATIVE PROJECT COST: $217,768

PROJECT MANAGER: Jonathan Skolnik

AFFILIATION: Jack Faucett Associates, Inc.

ADDRESS: 4550 Montgomery Ave. Suite 300 North, Bethesda Maryland 20814

PRINCIPAL INVESTIGATORS: Jonathan Skolnik, Chris D. Holleyman, John Schwochert

KEY WORDS: Beaufort Sea, IMPLAN, OCS Arctic Subregion, oil industry, economic 

impacts, employment, earnings, input-output, manpower.

BACKGOUND: Production of oil and gas in the offshore Alaskan Arctic relies upon a set

of technologies unlike those used anywhere else in the world. Remote locations, temperatures of 

60 degrees below zero, and shifting ice flows that rule out traditional platforms, waterborne craft 

and sea-floor pipelines are just a few of the challenges that must be overcome. The solutions

include roads and islands built of ice, man-made gravel islands, pipelines buried below the ocean 

floor, and cold weather retrofitted vehicles and equipment that are run for years without ever

being turned-off.

Economic impact modeling of these activities also requires a set of methods that are unique. 

Readily available regional economic impact models contain production functions that are based

on national averages. These national-level input coefficients cannot accurately reflect the unique 

arctic production function. These models are also unable to accurately trace the regional 

distribution of purchases made by the industry or the workers who commute to the site. Finally, 
these readily available models do no have enough detail to accurately model the differing impact 

of specific projects.

This report describes the development of a first step model that can be combined with a readily

available regional model to produce more accurate estimates of economic impacts. The first step 

model utilizes vectors of purchases, disaggregated by both geographic area and activity, to allow 

a more accurate accounting of the inputs required for a specific project. The vectors are

constructed by coding detailed engineering estimates of inputs to the individual activities. These 

direct inputs can then be used to stimulate the standard regional impact models.

OBJECTIVES: The Outer Continental Shelf Lands Act, as amended, established a policy

for the management of oil and natural gas in the Outer Continental Shelf (OCS) and for

protection of the marine and coastal environments. The Act authorizes the conduct of studies in 

areas or regions to determine the "environmental impacts on the marine and coastal

environments of the OCS and the coastal areas which may be affected by oil and gas

development." The U.S. Minerals Management Service (MMS) is the administrative agency

responsible for leasing submerged Federal lands.

The National Environmental Policy Act (NEPA) of 1969 requires use of the natural and social

sciences in any planning and decision making that may have an effect on the human

environment. To this end, the MMS prepares Environment Impact Statements (EIS) and

environmental assessments (EA); acquires marine environmental data; analyzes data, literature

surveys, socioeconomic studies, and special studies; and holds public conferences. These

undertakings often call for assessing the regional economic impacts of a proposal such as a lease 

or a sale. 

In the past, an assortment of models and methods were used to estimate economic impacts, and

these typically varied by planning areas. At present, the existing models used to develop direct

OCS and secondary employment projections for the Alaska OCS Region are outdated and do not 

produce results comparable to other OCS regions such as the Gulf of Mexico. As a result,

regional comparisons are difficult to make. Section 18 of the OCS Lands Act, however, requires 

that the U.S. Department of the Interior prepare a 5-year schedule of lease sales that considers

"an equitable sharing of developmental benefits and environmental risks among the various

regions." For this reason, MMS decided to standardize the approach used to estimate regional

economic impacts and has settled on IMPLAN, an economic input-output model, for that

purpose. 

To facilitate EIS work for Alaska's OCS Arctic subregion and to develop a tool for the "equitable 

sharing" analysis, a new model was developed. It can estimate industry employment and

expenditures, by region, of offshore oil exploration and development (E&D) activities in the

Beaufort Sea. The new model is known as the Arctic Impact Model for Petroleum in Alaska

(Arctic IMPAK). Unlike the current model, this new model is designed to produce a set of

outputs that can be used to stimulate IMPLAN.

In a parallel but separate study, a similar model was developed for the Sub-Arctic Alaska

Subregion. This second model is known as Sub-Arctic IMPAK.
DESCRIPTION: The Arctic IMPAK model forecasts the input requirements needed to carry 

out oil exploration and development on Alaska's Arctic OCS. In the previous section, the

methods used to develop vectors of commodity and labor input requirements on a per unit basis

were described. Multiplying these vectors by projected annual activity levels developed from an 

E&D scenario generates estimates of the total input requirements for each year in the forecast

horizon.

The Arctic IMPAK model is contained in a Microsoft Excel platform and is driven by data from 

the E&D report, as well as other data, which are manually input into the model. Since the

activities listed in the E&D reports are not identical to those used in IMPAK, the model has to

convert the E&D data into the corresponding IMPAK activity levels.

The model inputs are then transposed into a matrix compatible with the regional input-output 

matrices. An Excel array function is used to accomplish the task. The transposed input is then

multiplied by each region's input-output matrix to yield the total direct impacts by region and

IMPLAN sector. Again, an Excel array function is used to accomplish the matrix multiplication. 

Note that each year in the forecast horizon requires a separate formula.

STUDY RESULTS: The final output is a matrix that provides total input requirements by

IMPLAN sector separately for each year and geographic area. This output then becomes the 

input for the Microsoft-Access model developed by the MMS. The MMS model estimates the

ripple effects in each corresponding, proximate onshore area.

REPORTS: Jack Faucett Associates, Inc. 2002. Arctic Economic Impact Model for

Petroleum Activities in Alaska (Arctic IMPAK), Final Technical Report. Prepared for the U.S.

Department of Interior, Minerals Management Service, Alaska OCS Region, Anchorage, Alaska. 

Technical Report No. 164.

MODELS: ARCTIC IMPAK: An Economic Impact Model on CD-Rom
CONTENTS

Chapter Page

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

THE CURRENT MODELING PROCESS...................................................................................................2

PURPOSE AND OBJECTIVE......................................................................................................................2

ORGANIZATION OF THE REPORT .........................................................................................................3

1 IDENTIFICATION OF ECONOMIC ACTIVITIES .............................................................................5

1.1 OVERVIEW OF OIL AND GAS ACTIVITIES .............................................................................5

1.2 SEISMIC SURVEYS.......................................................................................................................7

1.3 OIL AND GAS DRILLING METHODS.........................................................................................7

1.4 OFFSHORE PRODUCTION STRUCTURES ................................................................................8

1.5 OIL AND GAS RECOVERY ........................................................................................................13

1.6 OIL AND GAS PROCESSING .....................................................................................................14

1.7 TRANSPORTATION OF PRODUCT...........................................................................................15

1.8 FACILITY ABANDONMENT OR REUSE .................................................................................18

2 SELECTION OF ECONOMIC ACTIVITIES .....................................................................................19

2.1 EXPLORATION AND DEVELOPMENT (E&D) SCENARIOS.................................................19

2.2 SELECTION OF MOST LIKELY TECHNOLOGIES .................................................................21

2.3 SELECTION OF ECONOMIC ACTIVITIES FOR MODELING................................................25

2.4 UNITS ............................................................................................................................................28

2.5 GEOGRAPHIC AREAS.................................................................................................................28

3 MODELS AND MODELING APPROACHES ...................................................................................29

3.1 MODELING ISSUES ....................................................................................................................29

3.2 THE MANPOWER MODEL.........................................................................................................31

3.3 THE RURAL ALASKA MODEL .................................................................................................42

3.4 THE IMPLAN MODEL.................................................................................................................47

3.5 OTHER REGIONAL AND LOCAL ECONOMIC MODELS......................................................49

3.6 CRITIQUE OF CURRENT MODELING PROCEDURE.............................................................51

3.7 ALTERNATIVE MODELING PROCEDURES...........................................................................52

4. ENGINEERING DESCRIPTION OF THE ACTIVITIES...................................................................57

4.1 SEISMIC SURVEY .......................................................................................................................57

4.2 NORTH SLOPE SUPPORT ..........................................................................................................61

4.3 GENERAL PASSENGER TRANSPORT .....................................................................................64

4.4 ICE ROADS AND ICE ISLANDS................................................................................................65

4.5 DRILL SHIPS, BOTTOM FOUNDED PLATFORMS AND SUB-SEA WELLS...............69

4.6 HELICOPTER SUPPORT.............................................................................................................74

4.7 LOCAL BARGE TRANSPORTATION...............................................................................76

4.8 WELL DRILLING.........................................................................................................................78

4.9 GRAVEL PRODUCTION ISLAND .............................................................................................83

4.10 EQUIP PRODUCTION ISLAND ............................................................................................90

4.11 PRODUCTION ISLAND OPERATIONS ................................................................................95

4.12 LOCAL GAS PRODUCTION...................................................................................................98

4.13 OFFSHORE AND ONSHORE PIPELINES .............................................................................99

4.14 SEA FLOOR PIPELINES .......................................................................................................104

4.15 LAND BASE OPERATIONS .................................................................................................107

4.16 SPILL CONTINGENCY .........................................................................................................109

4.17 FACILITY ABANDONMENT ...............................................................................................114

5. LABOR INPUTS................................................................................................................................116
5.1 OVERVIEW OF THE METHODOGY .......................................................................................116

5.2 ESTIMATES OF PRODUCTION EMPLOYMENT AND WAGES..........................................117

5.3 ESTIMATES OF NON-PRODUCTION EMPLOYMENT AND WAGES................................128

5.4 WORKERS BY PLACE OF RESIDENCE .................................................................................129

5.5 ESTIMATES OF SPENDING BY GEOGRAPHIC REGION....................................................131

5.6 ESTIMATES OF TAXES, SAVINGS AND PERSONAL CONSUMPTION............................132

5.7 FINAL ESTIMATES OF SPENDING BY AREA......................................................................133

5.8 OTHER EMPLOYEE RELATED COSTS..................................................................................134

6. PURCHASED SERVICES INPUTS..................................................................................................139

6.1 NATIONAL INPUT/OUTPUT DATA........................................................................................139

6.2 THE CALCULATION OF TOTAL PURCHASED SERVICES ................................................143

6.3 PURCHASED SERVICES BY GEOGRAPHIC AREA .............................................................145

6.4 FINAL ESTIMATES OF PURCHASED SERVICES.................................................................145

7 CAPITAL INPUTS.............................................................................................................................125

7.1 OVERVIEW.................................................................................................................................125

7.2 INVENTORY OF ASSETS USED IN EACH E&D ACTIVITY ...............................................126

7.3 COST ESTIMATES BY ASSET.................................................................................................126

7.3.1 Seismic Survey................................................................................................................127

7.3.2 North Slope Camp Support .............................................................................................127

7.3.3 General Personnel Transport (GPT)................................................................................128

7.3.4 Ice Roads and Ice Islands................................................................................................128

7.3.5 Move Platform.................................................................................................................129

7.3.6 Operate Drill Ship for Exploration..................................................................................129

7.3.7 Mobile Bottom Founded Structure (MBFS) for Exploration ..........................................129

7.3.8 Helicopter Support ..........................................................................................................130

7.3.9 Barge Support..................................................................................................................130

7.3.10 Well Drilling ...................................................................................................................131

7.3.11 Gravel Island Construction..............................................................................................131

7.3.12 Production Module Installation.......................................................................................132

7.3.13 Production Island Operations..........................................................................................133

7.3.14 Pipelines..........................................................................................................................133

7.3.15 Land Base Operations .....................................................................................................134

7.3.16 Spill Contingency............................................................................................................134

7.3.17 Mobile Bottom Founded Structure (MBFS) for Production ...........................................135

7.4 MARGINS ...................................................................................................................................135

7.5 REGIONAL PURCHASE COEFFICIENTS (RPC)....................................................................136

7.6 ASSIGNMENT OF EXPENDITURES TO IMPLAN SECTORS ..............................................136

7.7 CAPITAL EXPENDITURES BY IMPLAN SECTOR AND REGION......................................137

8. MATERIAL INPUTS.........................................................................................................................138

8.1 OVERVIEW OF MATERIAL PURCHASES.............................................................................138

8.2 EQUIPMENT FUEL USE ...........................................................................................................140

8.3 MATERIAL USES AT EMPLOYEE CAMPS AND QUARTERS............................................147

8.4 WELL DRILLING MATERIALS ...............................................................................................150

8.5 GRAVEL ISLAND MATERIALS ..............................................................................................153

8.6 PRODUCTION MODULE INSTALLATION MATERIALS ....................................................154

8.7 PRODUCTION ISLAND OPERATION.....................................................................................156

8.8 PIPELINE CONSTRUCTION MATERIALS.............................................................................157

8.9 MATERIALS FOR LAND BASE OPERATIONS .....................................................................158

8.10 DRILL SHIPS AND MOBILE BOTTOM FOUNDED STRUCTURES................................160

8.11 MATERIALS FOR LAYING SEAFLOOR TIE-BACK PIPELINES....................................162

9. GOVERNMENT, TAPS AND LOCAL GAS ACTIVITY VECTORS.............................................164
9.1 GOVERNMENT..........................................................................................................................164

9.2 TRANS-ALASKA PIPELINE SYSTEM ....................................................................................164

9.3 LOCAL GAS................................................................................................................................165

10. MODEL DOCUMENTATION ..........................................................................................................166

10.1 INSTALLATION.....................................................................................................................169

10.2 USER INTERFACE ................................................................................................................170

10.2.1 Documentation Screen ....................................................................................................170

10.2.2 Model Setup Screen.........................................................................................................170

10.2.3 Data Entry .......................................................................................................................178

10.2.4 Output Screens ................................................................................................................179

10.2.5 Manpower Graph.............................................................................................................180

10.3 MODEL PROCESSING ENGINE ..........................................................................................180

10.3.1 Conversion of Data Entry Input into IMPAK Activity Levels........................................180

10.3.2 Generation of Model Output ...........................................................................................189

10.4 LOCAL GAS PROCESSING..................................................................................................190

APPENDIX A: CAPITAL TABLES .......................................................................................................192

APPENDIX B: TOTAL REQUIREMENTS............................................................................................193
LIST OF EXHIBITS

Exhibit Page

2-1: SAMPLE E&D REPORT: REPRESENTATIVE DEVELOPMENT SCHEDULE

FOR SALE 195 ............................................................................................................................ 20

2-2: ACTIVITIES AND UNITS PROVIDED IN THE MMS E&D REPORT................................... 21

2-3: TECHNICAL OPTIONS FOR OIL AND GAS ACTIVITIES IN THE ARCTIC OCS ............. 23

2-4: PRIMARY AND SECONDARY ACTIVITIES – DRIVERS AND DEFAULT FACTOR ....... 27

3-1: UNIT AND TASK DESCRIPTIONS .......................................................................................... 32

3-2: FLOW CHART OF ARCTIC MAN-POWER MODEL.............................................................. 33

3-3: ACTIVITY, LOCATION, TERM AND SKILL LEVEL ASSIGNMENTS BY TASK ............. 37

3-4: AGGREGATION OF TASK MAN-MONTHS IN STEP III.A................................................... 38

3-5: ASSIGNMENT OF TASK MANPOWER TO LOCAL COMMUNITY.................................... 40

3-6: RURAL ALASKA MODEL........................................................................................................ 44

3-7: RAM EQUATIONS..................................................................................................................... 45

3-8: BASIC SETUP OF TABLE FOR NEW MANPOWER MODEL, ARCTIC IMPAK ................ 53

5-1: PRODUCTION WORKER MANPOWER ESTIMATES BY ACTIVITY .............................. 117

5-2: 1997 CENSUS DATA ON NON-PRODUCTION EMPLOYMENT AND PAYROLL .......... 128

5-3: NUMBERS AND WATES OF NON-PRODUCTION WORKER WAGES BY ACTIVITY

BY GEOGRAPHIC AREA........................................................................................................ 129

5-4: PERCENT OF PRODUCTION EMPLOYEES BY ETHNICITY, PLACE OF RESIDENCE

AND ACTIVITY ....................................................................................................................... 130

5-5: PERCENT OF SPENDING BY PLACE OF FULL-TIME RESIDENCE ................................ 131

5-6: SPENDING BY ALL WORKERS BY AREA.......................................................................... 133

5-7: PRODUCTION WORKER LODGING EXPENSES................................................................ 136

6-1: SELECTED OIL AND GAS INDUSTRY INPUT DATA FROM THE 1992 BEA

NATIONAL INPUT-OUTPUT TABLE.................................................................................... 140

6-2: SELECTED MISCELLANEOUS SECTOR INPUT DATA FROM THE 1992 BEA

NATIONAL INPUT-OUTPUT TABLE.................................................................................... 141

6-3: PERCENTAGE ESTIMATES OF PURCHASED SERVICES BY SECTOR AND

GEOGRAPHIC AREA FOR OIL AND GAS RELATED ACTIVITIES ................................. 144

6-4: PERCENTAGE ESTIMATES OF PURCHASED SERVICES BY SECTOR AND

GEOGRAPHIC AREA FOR SUPPORT ACTIVITIES ............................................................ 144

6-5: ESTIMATES OF PURCHASED SERVICES BY SECTOR AND GEOGRAPHIC AREA

FOR OIL AND GAS RELATED ACTIVITIES........................................................................ 146

7-1: EXPENDITURES FOR FABRICATION AND TRANSPORTATION OF PRODUCTION

MODULES................................................................................................................................. 167

8-1: ESTIMATES OF FUEL CONSUMPTION BY ACTIVITY..................................................... 175

8-2: MATERIAL CONSUMPTION ESTIMATES FOR A 300 PERSON HOTEL CAMP ............ 182

8-3: NUMBER OF EMPLOYEES USED TO ESTIMATE FOOD AND HOUSEKEEPING

SUPPLIES.................................................................................................................................. 183

8-4: EXPENDITURES BY MARGINS FOR CASING, TUBING AND WELL HEAD................. 184
8-5: SELECTED OIL AND GAS INDUSTRY INPUT DATA FROM THE 1992 BEA

INPUT-OUTPUT TABLE ......................................................................................................... 185

8-6: EXPENDITURES BY MARGINS FOR DRILLING FLUIDS, MUD AND CEMENT .......... 186

8-7: MATERIAL ESTIMATES FOR GRAVEL PRODUCTION ISLAND CONSTRUCTION .... 187

8-8: EXPENDITURES FOR MATERIALS USED IN GRAVEL ISLAND CONSTRUCTION..... 188

8-9: MATERIAL ESTIMATES FOR PRODUCTION MODULE INSTALLATION.......................188

8-10: EXPENDITURES FOR MATERIALS USED DURING INSTALLATION OF

MODULES TO EQUIP ONE PRODUCTION ISLAND.......................................................... 189

8-11: MISCELLANEOUS MATERIALS AND SUPPLIES FOR PRODUCTION ISLAND

OPERATION ............................................................................................................................. 190

8-12: MATERIAL ESTIMATES FOR OFFSHORE AND ONSHORE PIPELINE

CONSTRUCTION (PER TEN MILES) .................................................................................... 191

8-13: EXPENDITURES FOR MATERIALS USED IN PIPELINE CONSTRUCTION................... 192

8-14: MATERIAL CONSUMPTION ESTIMATES FOR ESTIMATES FOR GENERATIORS

AT LAND BASE OPERATIONS.............................................................................................. 193

8-15: INTRMEDIATE PURCHASES FOR VESSEL OPERATIONS .............................................. 194

8-16: EXPENDITURES FOR NON-FUEL MATERIALS USED IN LAYING SEAFLOOR

TIE-BACK PIPELINES............................................................................................................. 196

10-1 IMPAK ACTIVITIES AND RESPECTIVE UNITS................................................................. 200

10-2: BROAD SCHEMATIC OF ARCTIC IMPAK MODEL ........................................................... 201

10-3: E&D DATA ENTRY REQUIREMENTS AND RESPECTIVE UNITS .................................. 212
GLOSSARY

BP British Petroleum, Inc.

Cat Caterpillar, Inc. 

COTU Crude Oil Topping Unit

CPU Central Processing Unit

BEA Bureau of Economic Analysis

E&D Exploration and Development

GPS Global Positioning System

IBT Indirect Business Taxes

IFR Instrument Flight Rules

IMPAK Impact of Petroleum Activities in Alaska

I-O Input-Output

KW Kilowatt

Margin A cost category that splits the purchase price of a commodity into

various cost components. These categories include the production 

margin, transportation margins (the cost of shipping a finished

product from the factory gate to its ultimate destination), wholesale 

trade margins, and retail trade margins. A margin rate is a margin

cost divided by the total purchase price of the commodity.

MLLWL Mean Low Level Water Level

MMS Minerals Management Service

NIPA National Income and Product Accounts. A national accounting

system published by the U.S. Bureau of Economic Analysis.

NSB North Slope Borough

OCS Outer Continental Shelf

PCE Personal Consumption Expenditures. These numbers reflect

household purchases of commodities and services in an area and

should be used to estimate the induced impacts in a region. The
figures are derived from estimates of disposable income (total

income minus taxes and savings) and take into account differences 

between where income is earned and where it is spent.

PF Permanent Fund

Production Coefficient The cost of a production input divided by total industry output.

Production Manpower This term is used to identify personnel directly involved in oil

exploration, development and production activities. Management

and overhead personnel who are not directly involved in the

activities are not included.

RPC Regional Purchase Coefficient. The percentage of demand

accounted for by local production or a particular geographic

region.

RTK Real Time Kinematic

SIC Standard Industrial Classification 

SUV Sport Utility Vehicle

TAPS Trans-Alaska Pipeline System

VP Vibration Point. A geographic location used seismic surveys. 

VSM Vertical Support Member. A supporting framework used to

elevate pipelines several feet above ground.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 1 Arctic IMPAK

INTRODUCTION

The Outer Continental Shelf Lands Act, as amended, established a policy for the management of 

oil and natural gas in the Outer Continental Shelf (OCS) and for protection of the marine and

coastal environments. The Act authorizes the conduct of studies in areas or regions to determine 

the “environmental impacts on the marine and coastal environments of the OCS and the coastal

areas which may be affected by oil and gas development.” The U.S. Minerals Management

Service (MMS) is the administrative agency responsible for leasing submerged Federal lands.

The National Environmental Policy Act (NEPA) of 1969 requires use of the natural and social

sciences in any planning and decision making that may have an effect on the human

environment. To this end the MMS prepares Environment Impact Statements (EIS) and

environmental assessments (EA); acquires marine environmental data; analyzes data, literature

surveys, socioeconomic studies, and special studies; and holds public conferences. These

undertakings often call for assessing the regional economic impacts of a proposal such as a lease 

or a sale. 

In the past, an assortment of models and methods were used to estimate economic impacts, and

these typically varied by planning areas. As a result, regional comparisons were often difficult to 

make. Section 18 of the OCS Lands Act, however, requires that Interior prepare a 5-year 

schedule of lease sales that considers “an equitable sharing of developmental benefits and

environmental risks among the various regions.” For this reason, MMS decided to standardize

the approach used to estimate regional economic impacts and has settled on IMPLAN, an

economic input-output model, for that purpose. Using one model will help ensure consistency

from region to region. IMPLAN is the most widely used input-output model for estimating

regional economic impacts. 

The existing models used to develop direct OCS and secondary employment projections for

Alaska are outdated and do not produce results comparable to other regions such as the Gulf of

Mexico. The analysis of lease sales proposed in the OCS Oil and Gas Leasing Program for

2003-2007, will require data on the possible impacts on coastal and offshore areas resulting from 

E&D activities in the Arctic Subregion of the Alaska OCS.

To facilitate EIS work for Alaska’s North Slope Borough (NSB), this study develops a new

model that estimates industry employment and expenditures, by region, of offshore oil

exploration and development (E&D) activities in the Beaufort Sea. The new model is known as

the Arctic Impact Model for Petroleum Activities in Alaska (Arctic IMPAK). Unlike the current 

Manpower model, the revised model produces a set of output that can be used to stimulate

IMPLAN.

In a parallel but separate study, a similar model was developed for the Sub-Arctic Alaska

Subregion. This second model is known as Sub-Arctic IMPAK.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 2 Arctic IMPAK

THE CURRENT MODELING PROCESS

Analysis of lease sales in all areas begins with the Exploration and Development (E&D)

Scenarios. The DBMat refers to any model that translates the E&D Scenario into direct effects

as a first-step model. Direct effects are defined as those resulting from the first round of

spending by companies working directly on an OCS project(s). The first-step model must

estimate the level of industry expenditure (or employment) and how that spending/employment 

is allocated to onshore geographic areas. The MMS calls the spending allocation to industry a

“cost function” and these cost functions are used to customize the inputs for IMPLAN.

In Alaska, the current first-step model is the Manpower model. It simply converts OCS activities 

levels (number of wells drilled, platforms installed, pipeline miles laid, etc.) into estimates of

direct employment using ratios such as employees per mile of pipelines laid. It was developed in 

the late 1970s and then refined in the early 1980s. The main objective of this study is to update 

this model.

The second-step model is used to estimate the additional impacts that result as the initial

spending reverberates throughout the economy. These secondary impacts are often referred to as 

indirect and induced effects. Such models must be developed specifically for OCS or must be

customized to reflect the unique expenditure and commuting patterns of OCS-related companies 

and their employees. For Alaska, these problems are exacerbated by the fact that national

models like IMPLAN often use national multipliers due to inadequate local data.

In Alaska, the second-step model currently being used is the Rural Alaska Model (RAM),

developed by the University of Alaska. Like Manpower, RAM is a set of spreadsheets that uses 

simple multipliers to estimate results. It was originally built in the early 1980's and updated in

1995. Another option for use as a second-step model for Alaska is the Man-in-the-Arctic 

Program (MAP) model developed by the University of Alaska Anchorage for MMS in the

1980's. This model estimates indirect and induced impacts at the state level, rather than at the

regional level.

PURPOSE AND OBJECTIVE

The purpose of this study is to develop a model to replace the Manpower Model for E&D

activities that place in the Arctic OCS. Since the early 1980s, there have been significant

technological changes in offshore E&D activities. In addition, the production process used in

Alaska’s arctic regions differs significantly from the process used in the sub-Arctic regions. 

E&D activities specified in the current model were examined and revised.

As stated above, MMS would prefer to use very similar procedures and the same modeling

software in each region to ensure comparability across regions. This would improve the quality

of the equitable sharing analysis. However, the unique conditions in Alaska may result in

questionable results from some of the readily available national models such as IMPLAN. 
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 3 Arctic IMPAK

Therefore, before adopting IMPLAN for use in analyzing Alaskan activities, MMS would like to 

run some tests and compare IMPLAN results with results generated by RAM.

In developing the new model, the latest available data were used to develop employment and

expenditure factors for the revised E&D activities. With these updated factors, projections of

direct and indirect employment impacts in the sub-Arctic region will be more accurate. With

more accurate projections, stakeholders will have more confidence n the economic sections of an 

EIS. More accurate projections may also be used in decisions regarding post-lease mitigation.

The new first-step model converts E&D inputs into direct employment and expenditure impacts

for the North Slope Borough (NSB), the rest of the state of Alaska, and the rest of the United

States. Expenditure impacts are itemized by IMPLAN sector. It is expected that MMS will enter 

these impacts into IMPLAN to estimate the indirect and induced effects. 

This study meets MMS needs to verify IMPLAN-based outputs by developing a first step model 

that produces consistent inputs for RAM and IMPLAN. This could also include MAP, if MMS

deems it affordable and worthwhile.

ORGANIZATION OF THE REPORT

The economic impact of a particular set of oil and gas activities on the North Slope will depend

on both the size of the project and the set of technologies chosen. In the first chapter of the

report, alternate technologies are first defined and then the most reasonable and likely set of

technologies are chosen.

In the second chapter, these choices are then contrasted with the categorization of activities

contained in basic MMS projections of economic activity and a set of twenty-three activities

chosen for inclusion in the model. The activities are then defined in terms of the support

activities required including (hotel/camps, personnel transport, ice roads, helicopter support and

barge support.). Finally for the chosen set of twenty-three activities, a basic unit of activity (mile 

of pipeline, number of barrels, etc.) is chosen.

The third chapter examines alternative modeling processes for determining the economic impact

of Beaufort Sea OCS development. The chapter begins with an examination of the modeling

issues that arise due to the unique aspects of Beaufort Sea OCS development. Next, the three

key economic models are reviewed followed with shorter synopses of a few additional models. 

The three key models include the Manpower model, the Rural Alaska Model (RAM) and

IMPLAN. The basic purpose and functions of the models are reviewed and their strengths and

weaknesses are analyzed. The chapter closes with two sections, the first of which discusses the

current modeling approach. The second proposes some alternatives and identifies the preferred

alternative.
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The fourth chapter provides a detailed summary of the engineering and economic information

collected for the various activities. Included are general descriptions of the engineering specifics 

of the activity, the sources of the data, and summaries of manpower requirements, capital needs

and fuel and material inputs.

The fifth through ninth chapters provide overviews of the methods used to develop the inputs to 

the 26 activities. In some sense, this study develops a production function for each activity,

where the production function is defined in terms of expenditures for various types of inputs. 

These inputs can be broadly grouped into the following categories: labor, purchased services,

capital and materials with the latter including raw, intermediate and energy material and inputs. 

Labor inputs are discussed in Chapter Five, purchased services in Chapter Six, capital inputs in

Chapter Seven and material inputs in Chapter Eight. The ninth chapter describes how

expenditure patterns were developed for several special activities that are treated differently than 

the other activities in the model. Among these are government activities, the Trans-Alaska 

Pipeline System (TAPS), and local gas development.

The tenth and final chapter provides an overview of the IMPAK model. Included are sections on 

model inputs and outputs.

The per-unit cost/manpower vectors developed in chapters five through nine serve as a

foundation for the IMPAK modeling software described in chapter ten. In Appendix B, these 

vectors are itemized by region, activity and major input category.
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1 IDENTIFICATION OF ECONOMIC ACTIVITIES

The economic impact of a particular set of oil and gas activities on the North Slope will depend

on both the size of the project and the set of technologies chosen. In this chapter alternate

technologies are defined and described. In the following chapter, the set of technologies most

likely to be used on the North Slope are chosen for further analysis.. 

The basis for the description and evaluation of the technologies available and likely to be used is 

based on two major information sources: the Draft Beaufort/Northstar EIS published in June of

1998 and a series of interviews with industry personnel conducted specifically for this study.

1.1 OVERVIEW OF OIL AND GAS ACTIVITIES

The development of offshore oil and gas involves a series of distinct economic activities. These

activities are generally categorized into two phases, exploration and development/production

with multiple activities occurring under each phase. Specific activities include the following:

Exploration:

• Seismic Surveys - Exploratory seismic surveys collect data used to interpret subsurface

geology. These surveys also occur during production.

• Exploration Drilling - Exploration drilling is conducted to confirm the presence of

recoverable resources, and to evaluate potential volumes. Several wells are typically

required to provide sufficient data to prepare a development/production plan.

Development/Production:

• Development/Production Drilling - This activity typically involves the installation of

several oil production wells. In addition, reservoir development may require water or gas 

injection wells. Operation of production wells involves routine well maintenance

procedures, some of which require a workover rig (a type of drill rig).

• Oil and Gas Processing - Processing facilities may be located at the production site if

sufficient space is available, or they may be located at a distant site. Sometimes produced 

fluids are only partially separated into oil, gas, and produced water components prior to

transport to offsite processing facilities.

• Transportation of Produced Fluids - Produced fluids may be transported from offshore

sites by pipeline, marine tankers, or barges during open water, and pipelines or trucks

during winter. Pipelines, railroad, and trucks may be used year-round at onshore

locations. Existing offshore production facilities are connected to shore by gravel
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causeways which protect pipelines. Buried subsea pipelines have never been used in the 

Alaskan Beaufort Sea, but were tried in the Canadian Arctic. Subsea buried pipelines are 

planned for the Northstar and Liberty projects.

• Facility Decommissioning and Abandonment - When a production facility reaches its

economic limit, wells are plugged and surface structures may be removed. Facilities may

be reused in place, transported for use at another location, removed for salvage or

disposal, or prepared for abandonment in place.

In addition, construction and operation of these facilities frequently results in the need for

development of gravel mines, freshwater sources, roadways (including ice roads),

airstrips/heliports and waste collection and disposal systems. Other economic activities related

to these activities include personnel transport to and from the region, related activities such as

hotels, transportation of equipment and environmental protection schemes, especially those

related to oil spill protection and cleanup.

An important part of the technology not discussed in detail in the draft Beaufort/Northstar EIS

are ice roads and ice islands. The following description of the technology for these roads was

developed from several interviews conducted specifically for this study.

Ice road construction takes about a 40-man crew, a small grader and snow blower equipped with 

floats (capable of operation on 8 inches of ocean ice), four Rollagon pumpers, three water trucks, 

two dump trucks, one ice mill, one grader, and nine pickup trucks. The first step is to proceed on 

about 8 inches of ice with the small grader and snowblower removing the snow from the ice road 

path. This can normally occur about the last half of December. The snow removal process is

ongoing through construction and the ice road service life (about May 1

st). Next, the Rollagon

pumpers are placed in service. They drill and pump in the same operation. They relay around

each other up and down the ice road until the ice is thick enough for larger vehicles. The road is 

then staked with reflectors to identify the profiled road edges. Fresh water and milled ice chips

are used to make ramps from shore to the ice and supplement the salt water drill/pump operation. 

The ice chips are hauled with dump trucks and the fresh water with water trucks equipped with

fan spray nozzles. Any cracks that appear are repaired with fresh water to keep the road from

separating and drifting. The construction process continues until the road is thick enough or

grounded to handle the loads for which it will be used, including drilling rigs.

The same process is used in ice island construction; however, the entire island must freeze to the 

bottom and ground. Ice chips and fresh water are used as much as possible to insure the island is 

stronger than the surrounding sea ice. All equipment must be back on shore by May 1st. Bags of 

sand are used to protect the island edges from moving sea ice.

A brief description of oil and gas facilities and technologies that may be applicable to

development in the Alaskan Beaufort Sea is presented in the following subsection.
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1.2 SEISMIC SURVEYS

Seismic surveys are conducted to collect subsurface geologic data. Although primarily associated 

with exploration, seismic surveys are sometimes conducted in producing fields to provide data

used to refine field development plans. In the Arctic, offshore seismic surveys are conducted

during open water periods (August to September) or winter time (February to April). Open water 

surveys are conducted by a survey vessel equipped with an air gun to create a sound wave and a 

towed array of hydrophores to record these reflected wound waves. Support vessels are often

used for logistical support and ice management activities.

During the winter, seismic surveys are conducted from the ice surface. The sound source for

these surveys is a large vibrating plate mounted on a wheeled vehicle. Geophones are placed on

the ice surface and record reflected sound waves.

An interview for this study was conducted with an individual who was on a drill ship about 200 

miles west of Barrow Alaska (10 miles from Russian waters). 

This individual was also involved with offshore surveys on ice. Travel on the sea ice is not safe 

until some time in January until approximately May 1st. A seismic cat train consists of about

115 men, 3 D8 Cats, 9 Bombardiers, 6 Nodwell geo-phone rigs, 1 Foremost CPU data collection 

rig, 1 966 snowplow and 2 support modules. A survey crew goes out first staking four lines

about ten miles long. These are followed by the snowplow leveling the larger drifts followed by 

six Nodwells with "jug hounds" setting four rows of Geo-phones that are then connected to the

Foremost CPU data collection rig. Eight to ten shaker trucks are then positioned along the tenmile long line. The vibrations are collected to form a map of underground formations.

1.3 OIL AND GAS DRILLING METHODS

Characteristics such as water depth, distance from shore, and reservoir characteristics such as

depth, thickness, degree of faulting, permeability and porosity, and areal extent will determine

drilling options. There are two drilling methods: 1) conventional vertical drilling in which the

well is drilled straight down; and 2) directional drilling in which the well is drilled at an angle.

Production from a vertical well is limited to the portion of the reservoir located beneath the

wellhead, and multiple surface locations would be required to develop a reservoir that has a large 

areal extent. In contrast, directional drilling allows for access to multiple bottom hole locations

from a single surface facility. A large number of surface structures are not practical for cost,

logistic, safety, and environmental reasons.

Directional drilled wells typically cost approximately two to three times more than a

conventional vertical well. Much of the additional cost is associated with the equipment to

ensure wells intersect the desired locations. Directional wells also take more time to drill

because they are often much longer.
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The location of the reservoir and technology limit the range of drilling sites. The range of

locations include onshore, on existing offshore islands or a new offshore location.

1.4 OFFSHORE PRODUCTION STRUCTURES

Selection of drilling and production structures is based on the site-specific environment of the

offshore reservoir and project economics. In addition, oil recovery and processing methods,

options for transportation of product, people and supplies, and relationships between onshore and 

offshore facilities influence structure location. This section presents a brief description of the

components of drilling and production facilities and a comparison of drilling and production

structure options.

Components of Production Facilities

Drilling Rig and Associated Equipment: The drilling rig contains power generation units, a

drilling mud system (tanks, cuttings removal screens, pumps), a cementing system, and a storage 

area for drill pipe, drilling mud, cement, and well casing.

Oil/Gas/Water Separator System: One to three multi-phase bulk oil separators are used to

decrease the pressure of produced fluids and remove natural gas and water. Separators are

located on the offshore structure and/or onshore sites.

Water Treatment and Injection System: Water produced with the oil is routed to a clarification 

system consisting of a series of vessels that separate oil from water by gravity, electrical, or

centrifugal force. Clarified water is pumped to a disposal well or a pipeline.

Gas Dehydration and Compression System: Gas removed from produced reservoir fluids is

routed to coolers that use air and/or seawater for cooling, and into vessels that separate the

remaining water from the gas. Low pressure gases are compressed by a series of turbine-driven 

and/or electric-driven compressors. The gas may be injected to the reservoir, used on site as

fuel, or transported by pipeline.

Seawater Systems: Seawater is used for fire suppression, for waterflood, to supply potable water, 

and to cool processing equipment.

Emergency Flare: Flares are tall structures with a small stream of gas feeding a continuous pilot 

flame. that protects processing systems during startups and shutdowns, and provides emergency

gas pressure relief.

Chemical Treatments: Includes tanks and small electric-driven pumps to inject chemicals such as 

emulsion breakers, corrosion inhibitors, biocides, and anti-foaming agents into producing wells

and pipelines.
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Electric Power Generation: Electricity is provided by at least one main and one emergency

generator.

Fire Suppression: The main components of this system are water storage pump and distribution

piping.

Other facilities include offices and a control room, a potable water system, a wastewater

treatment system, heating and cooling systems, storage and shop areas, and living quarters. Ship 

docking facilities and a helicopter landing area are also likely.

Gravel Islands

Because a natural island would function similar to an artificial island, differentiation will not be

made here.

Manmade gravel islands are constructed by placing gravel on the seafloor until the mounded

gravel is above sea level. After an island is created, slope protection may be used to prevent

erosion by waves and moving ice. Historically, the practical limit of water depth for a man-made 

gravel island appears to be about 50 feet (15.2 m) because of the logistic and economic

constraints related to the amount of gravel required to create an island in deeper water. However, 

in theory, the water depth for gravel islands is not limited. The location of the source material for 

the island and hauling time/distance greatly influences its cost. Usually at least some of the

material would be brought from a site on land because sediments dredged from the seafloor tend 

to be too soft to support facilities. 

Gravel islands typically have side slope ratios of approximately 1:3 (vertical:horizontal), with the 

island surface 10 to 23 feet (3 to 7 m) above sea level. Some islands were constructed with side 

slopes as flat as 1:20, resulting in a beach-like slope structure that can withstand the elements

without affecting the integrity of the island's working surface. Sandbags, interlocking concrete

blocks or mats, or steel walls may be used to help protect island slopes from wave and ice

erosion. Gravel islands are inexpensive to repair by replacing or reshaping gravel and slope

protection. Construction costs for gravel islands typically range from $10 to $40 million,

depending on size of the island and water depth.

Ice Islands

Ice Islands are created by pumping seawater onto the frozen sea ice sheet until the ice is

grounded or is thick enough to accommodate the weight of a drilling rig. Ice islands would be

used for exploration drilling for only one winter because they melt.

Mobile Bottom-Founded Structures

Mobile, bottom-founded structures are those that rest on the seafloor, but can be floated and

towed to different locations. Designs for mobile, bottom-founded structures were developed to
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conduct offshore exploratory drilling in the Arctic during the 1980s. Several different one-of-akind structures of this type were used and remain in Arctic or northern waters. 

One of a kind structures such as the Caisson Retained Island (CRI) and the concrete caisson

island (Tarsiut), were designed to increase slope protection and decrease gravel fill requirements 

over a conventional gravel island.

The caisson island designs are limited to 11.5- to 70-ft (3.5 to 21 m) water depth and have

demonstrated durability and stability in ice.

The Concrete Island Drilling Structure (CIDS) consists of a steel base that rests on the seafloor

and a concrete unit that extends through the surface water/ice zone. CIDS has drilled four

exploration wells in the Alaskan Beaufort Sea.

The CIDS was not designed for oil and gas development/production activities; however, the

owners have proposed to modify CIDS to accommodate such facilities. Proposed modifications

include reconstructing the current drilling equipment layout, adding production equipment,

allowing space for 22 wells, and an additional deck for a maximum of 35 wells. The CIDS is 

limited to 35- to 55-ft (10.7 to 16.8 m) water depths and would require modifications in dry dock 

costing approximately $70-75 million.

The Mobile Arctic Caisson (Molikpaq) is an eight-sided steel caisson constructed as a

continuous ring, creating a hollow center which is filled with sand or gravel and working top

deck. The caisson has outer dimensions of approximately 366 ft (112 m) per side at the base and 

approximately 241 ft (73 m) per side on the working deck. The caisson is divided into 12 ballast 

compartments filled with sea water.

The Molikpaq began operations in 1984 and has drilled 10 wells in the Canadian Beaufort Sea. 

The Molikpaq was not designed to support oil and gas development/production activities.

However, the owners proposed to modify the Molikpaq to accommodate

development/production facilities. 

The Molikpaq is limited to 30- to 130-ft (9 to 40 m) water depths and would .require

modifications to accommodate a long-term development/production program with modification

costs expected to be between $85 and $112 million.

The Single Steel Drilling Caisson (SSDC) is a modified, very large crude carrier (super tanker)

that conducts exploratory drilling operations in open water and ice. The SSDC has been

previously used to drill exploration wells in the Alaskan Beaufort Sea; however, only one

location is in the project area.

The SSDC was not designed for oil and gas development/production activities; however, the

owners proposed to modify SSDC to accommodate drilling and production facilities. Proposed

modifications include reconstructing the current drilling equipment layout to add production
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equipment and allow space for 30 to 40 wells. Long-term maintenance requirements are

unknown.

The SSDC is limited to 25- to 100-ft (7.6 to 30 m) water depths and .would require modifications 

to accommodate a long-term development/production program with modification costs estimated 

to be approximately $113 million.

These bottom-founded structures or others that could be designed and constructed to meet

specific project needs are feasible options within the limits discussed for drilling and production 

structures in the Alaskan Beaufort Sea. The structures have a record of success in withstanding

sea ice and other cold weather operating conditions.

Sinkable Island Drill Ship (SIDS)

Interviews for this study discovered an additional bottom founded structure that can be floated

from site to site that was not mentioned in the literature. The SIDS is a very large barge

equipped with a drilling rig. The ship is loaded with drill stem, casing, drilling mud, and all the 

other major supplies necessary to drill several wells. It is then towed to a drilling site that has

been prepared by a barge with a large crane on it to assure the bottom does not have any large

rocks and is fairly level. The SIDS is then positioned over the drill site and sunk to the bottom in 

30 to 50 feet of water. "Flex-a-barges" deliver day to day supplies. These barges are constructed 

with individual sections that can be added or subtracted to change the barge sizes to meet the

needs of the day. Power drive sections can also be added or subtracted. The barges have a three 

to 4-man crew and can be used from mid July to the first part of October. Ice road support can

begin in January and continues until May. Only helicopter support can be used from October to

January and May to mid-July. The interviewee also has crew boats, fuel barges, and camp

barges that can be used for exploration and drilling island support.

Subsea and Subterranean Structures

In areas where ice movements or gouging of the seafloor would endanger an exposed structure,

facilities could be placed deep enough below the seafloor to prevent damage. Construction of

such facilities would be expensive, and would generally require a large reservoir or special site

conditions to justify this expense.

A subsea cavern is similar in design to an underground mine. A cavern would likely have an

access tunnel from land which would also be used for removal of excavated material and for

transport of produced oil and gas to shore.

Subsea silos, similar in concept to underground missile silos, have been considered to develop

the Kuvlum reservoir in the Alaskan Beaufort Sea. The conceptual design includes produced oil 

and gas reaching shore through a trenched pipeline. Plans for this development or other silos in

the Alaskan Beaufort Sea are not anticipated in the near future.
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Subsea Templates

Seafloor templates, which rest on the surface of the seafloor, are used in many offshore regions

as a drilling guide and to house wellheads. Drilling equipment is positioned over a template and

wells are drilled and brought into production using pipelines. A seafloor template with multiple 

wells is more economical than single well templates, but also increases the size of the structure

that rests on the seafloor. The largest operating multi-well seafloor template is in the Gulf of

Mexico.

Seafloor templates could be used in water depths greater than 200 feet (61 m) in the Alaskan

Beaufort Sea, where ice grounding or gouging do not occur. At these depths, a floating vessel

would be used to drill the wells. It may take a full 2- to 3-month summer season to drill a single

well.

Floating Drilling Structures (Seasonal Use Structures)

Floating drilling structures have limited usefulness in the Arctic unless conventional designs are

modified for ice protection. Even with modifications, a floating structure is not considered

suitable for year-round development/production activities because it could be moved and/or

damaged by ice. Seasonal drilling and workover activities in combination with a seafloor

template or subsea silo enclosed template are potential production-related uses of floating

drilling structures. Ice islands could be used to extend the potential workover schedule.

Jackup Drilling Platforms are towed and positioned over a specific drilling location. Three legs

are lowered to the sea floor. Jackup platforms have been used to support exploratory drilling 

activities in waters less than 100 feet (30 m) deep.

Semi-Submersible Drilling Vessels are self-powered or towed steel-hulled platforms that are

positioned over a specific drilling location. Semi-submersibles can operate in waters between

100 and 1,000 feet (30 and 305 m) deep.

Drillships are self-powered, steel-hulled platforms that are positioned over a specific drilling

location. Drillships have operated in the Beaufort Sea since 1976. Drillships can operate in

waters between 100 and 1,000 ft (30 and 305 m) deep.

The Conical Drilling Unit (Kulluk) is a one of a kind floating exploration drilling vessel

designed for extended season arctic operations in light to moderate ice conditions. It is towed to

and positioned over a drilling location. The double-walled, inward-sloping hull is in the form of

an inverted cone that flares at the bottom causing ice to break downward and away from the hull. 

 The Kulluk has drilled one exploration well in the Alaskan Beaufort Sea and is considered

practical in up to 328 ft (100 m) water depths.
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1.5 OIL AND GAS RECOVERY

Varieties of technologies, ranging from those relatively unchanged for more than a century to

modern state-of-the-art technologies, are used for oil and gas recovery. These technologies are

usually referred to as primary, secondary, or enhanced (tertiary) recovery.

Primary Recovery

Primary recovery (or "natural blowdown") uses only the reservoir's natural pressure to force

crude oil from the underground reservoir. As the reservoir is depleted, pressure drops, resulting

in a decline in recovery rates. Natural blowdown was used with the earliest oil wells and results

in an average recovery of only 5 percent to 20 percent. Some developments employ natural

blowdown early, and then add a secondary recovery method.

Natural blowdown is a reasonable option for a fairly large reservoir, or one that would have

difficulties in implementing pressure enhancement. A deep water site could be developed with

sea floor templates and natural blowdown using minimal investment.

Secondary Recovery

Secondary recovery options are designed to improve oil recovery from the reservoir. This is

accomplished by boosting or maintaining reservoir pressure or by lifting fluids in individual

wells. Secondary recovery options include injecting gas or water into the reservoir to maintain

reservoir pressure as oil, gas, and water are produced. These secondary recovery methods include 

gas lift, reservoir maintenance with gas (gas cycling), reservoir maintenance with water

injection, and waterflood.

Availability of water or gas from another source is a factor in choosing an appropriate secondary 

oil recovery technology. A combination of recovery methods may be used, depending upon

reservoir characteristics.

Gas lift involves injecting natural gas at high pressure to introduce small bubbles into the

oil/water column in the well. The gas bubbles lighten well fluids, allowing them to rise. Gas lift 

is effective particularly if the reservoir contains heavy, thick oil or if it has high water content.

Gas lift requires a gas supply, either from the producing reservoir or an external gas source. The 

amount of gas needed is small relative to gas cycling and usually can be supplied by the

producing reservoir.

Gas cycling involves reinjecting natural gas through dedicated injection wells into a reservoir's

overlying gas layer (the reservoir's gas cap) or into the oil producing zone. The reinjected gas

preserves or enhances reservoir pressure. Because gas cycling requires 1 to 1.5 times the amount 

of gas normally produced daily, an external, supplemental natural gas source may be necessary. 

Typical reserve recovery rates range from 45 percent to 65 percent.
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Water Injection is use where oil/gas reservoirs have aquifers beneath the oil reservoir and water 

injected into the underlying aquifer causes upward pressure on the oil layer. Some of the water

injected may be produced water separated from reservoir fluids. One to two times the amount of 

fluid produced from the reservoir is required. Water from another source, such as seawater, can 

be treated and injected. Water is injected at pressures above existing reservoir pressure through

dedicated water injection wells. Typical water injection recovery rates are 35 percent to 45

percent of reserves.

Waterflooding involves injecting treated produced water or seawater directly into the oil

reservoir through dedicated injection wells. Water is injected in a specific pattern, to flush oil

toward oil production wells. Typical reserve recovery rates range from 40 percent to 50 percent 

of reserves.

Enhanced (Tertiary) Recovery

These options can be employed once secondary recovery options are no longer effective.

Enhanced methods include chemical flooding, miscible flooding, and thermal techniques.

Chemical flooding methods (e.g., polymer, surfactant, and alkaline flooding) improve oil flow by 

the addition of chemicals. Miscible flooding uses carbon dioxide, nitrogen, or hydrocarbons as a 

solvent. Thermal processes add heat to improve oil flow. Enhanced recovery is not considered

until recovery declines dramatically. Only miscible flooding with hydrocarbons has been used

on the North Slope.

1.6 OIL AND GAS PROCESSING

Produced reservoir fluids are processed by separating crude oil, water, and gas. The processing 

facilities for an offshore reservoir may be located offshore, onshore, or with parts in both

locations. Processing requirements depend upon reservoir characteristics, production rates, and

secondary recovery methods. These requirements also differ depending upon a reservoir's

distance to shore and proximity to existing facilities. Considerations for determining an

appropriate processing option include distance to existing processing facilities, method for

transporting product, and size of production structure required for processing facilities.

Fluids produced at the wellhead are called "three-phase fluids." Partial processing removes much 

of the gas and some of the water from the oil. Pipelines can be used to transport unprocessed,

partially-processed, or fully-processed crude oil. Pipelines carrying three-phase fluids are not

technically feasible for distances greater than 12 miles (19.3 km) because inconsistent mixtures

make pumping difficult. Tankers and barges are unable to transport three-phase fluids because

they are not pressurized. Fully processing the crude oil fluids produces both uniform crude oil

that then can be transported by a variety of vessel types and a uniform gas product that can be

reused on site for secondary recovery or transported by pipeline.
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Because of the cost of processing equipment, a small reservoir may not support a processing

facility; however, in combination with others, it may be economical. Offshore reservoirs within

the range of a three-phase pipeline could be developed by connecting to existing processing

facilities. If excess capacity is not available, the distance is too long, or transport of mixed-phase 

fluids is to be avoided, processing can be done at a new offshore site.

Site-specific concerns influence selection of a processing site, but the more likely factors are

reservoir economics and product transportation. In water depths less than 100 ft (33 m) where a 

stable structure can be placed and protected from ice, full processing is expected to be proposed 

because it avoids three-phase transportation problems. In deeper water, other alternatives may be 

considered. Since none have been seriously considered however, it is difficult to predict what

technology may be proposed.

1.7 TRANSPORTATION OF PRODUCT

Transportation of oil and gas products to world markets could be accomplished by a variety of

methods such as vessels, pipelines, railroad, or trucks. It is expected that the existing TAPS

pipeline and Dalton Highway would be used onshore rather than developing duplicate facilities. 

For offshore there are no existing pipelines, ports, fuel storage, or shipping facilities. Thus new

systems would be required. Some reservoirs may be located in areas which prohibit use of the

TAPS or the Dalton Highway so new onshore systems may also be proposed. Listed below are

transportation options and a summary of their limitations.

Offshore:

• Tankers to market - product must be processed to crude, ice breaker support required,

seasonal shipping.

• Barges to coastline - same as tankers plus shoreline transfer and onshore facilities

required.

• Pipeline to shoreline - three-phase, gas, or crude oil transport possible; new pipeline

required; year-round operation.

Onshore transportation:

• Railroad - product must be processed, new railroad system required, year-round 

operation.

• Trucks - product must be processed, year-round on existing roads.

• Pipeline - three-phase, gas or crude oil transport possible; use of new or existing pipelines 

including existing common carrier pipelines and the TAPS; year-round operation.
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Railroad and truck is unlikely to occur because of the perceived need to find additional oil to

keep TAPS in operation as Prudhoe Bay production declines. Rail and truck transportation also

have higher spill risk than pipelines because of increased transfers. For these reasons, use of

either railroad or truck transport of crude oil from the North Slope is considered unlikely. Use of 

tankers, barges, and pipelines are discussed below.

Tankers

If an offshore production facility has full processing, tankers could carry the oil directly to world 

markets. Such a system would require a mooring and loading system and large capacity storage

to hold products between callings. Small and super tankers require a minimum of 60 ft (18.3 m) 

and 120 feet (36.6 m) of water depth, respectively. Therefore, a channel must be dredged in

shallower waters. Alternatively, a pipeline to a tanker loading site in deeper water could be

constructed. Ice management would be required for much of the year. The use of tankers was

attempted in 1969, however, it was determined that tankering could not compete economically

with an onshore pipeline system. Offshore reservoir development may reopen the question of

tankering. 

Barges

Barges could be used for transport of crude oil between an offshore site and the shoreline. A

dock, such as existing facilities at Oliktok Point, West Dock, East Dock, and Badami may be

used to reach the required water depth. Occasional or frequent dredging may be required. 

Barges usually can operate between late July and mid- September; however, ice breaker support 

would be required to extend the shipping season. Barge transport would also require

construction of a loading/unloading facility connected by pipeline to the TAPS. Barges also

present an increased risk for oil spills to occur during barge loading/unloading activities.

Barging crude oil to the shoreline for transport through the TAPS may be feasible. When a

pipeline cannot be constructed, barging may be the only remaining option; however, this is likely 

to result in only seasonal production from the offshore site.

Pipelines

Pipelines could transport three-phase fluids or crude oil to the coastline and on to existing oil and 

gas facilities or to the TAPS. Pipeline installation may occur on gravel-filled causeways,

elevated pile-supported structures, the seafloor, or buried or drilled beneath the seafloor. A

combination of these methods may be used.

Once pipelines reach the coastline, onshore pipelines constructed on elevated vertical support

members (VSMs) or other types of pipelines would depending on the landfall site, join existing

routes, tie-in to a common carrier pipeline, or be the first pipeline in the area.
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Onshore Pipelines Corridor: Onshore pipelines installed on elevated VSMs are currently the

conventional method on the North Slope. Selection of an onshore pipeline route would consider

environmental issues, project cost, and access to the pipeline. These factors may include

maximizing use of existing disturbed area such as pipeline corridors, avoiding high value fish

and wildlife habitat, minimizing length and expense, and avoiding conflicting land uses.

Gravel-filled Causeways: Causeways are manmade structures that connect offshore facilities to

the mainland. They are constructed by placing gravel onto the seafloor. Pipelines are installed

on top of or within the causeway. The causeway protects the pipeline from waves and ice, and

provides access for maintenance. Gravel-filled causeways can be continuous or broken by

openings that allow small vessels, water, and organisms to pass. The breaches are bridged for

vehicle travel and pipeline support.

Causeway construction is most practical when the offshore facility is located in shallow water

and close to shore. Existing causeways are 3 to 5 miles (5 to 8 km) in length and extend to water 

depths of 12 to 14 ft (3.4 to 4.3 m). Impacts of causeways on coastal circulation and fish

movements preclude their use along some portions of the coastline.

Elevated Pile-Supported Structures: A pile-supported pipeline would extend above sea level

allowing water and fish to pass unimpeded; but possibly presenting an impediment to navigation. 

 Due to winds, wave action, and ice forces, it is most suited for facilities close to the shore. Even 

in the bottomfast ice zone, the pipeline would be at risk from moving ice during breakup and

freeze-up. Due to costs and the limited distance they could be used offshore, this option is not

considered reasonable.

Installed on the Seafloor: A pipeline from an offshore facility may be laid directly on to the

seafloor in many regions. In Alaska, however, ice would likely rupture or damage pipelines out 

to depths of about 200 feet (61 m). In deeper water pipelines could be laid on the seafloor.

Buried Beneath the Seafloor: The only arctic subsea buried pipeline was constructed in the

Canadian Beaufort Sea in 1978. The pipeline was tested by allowing a limited quantity of gas to 

flow from a well that was never placed into operational service. It was intended to become part

of a larger transportation scheme, but these facilities were never built. Since the pipeline was not 

placed into service, there was no program of monitoring or maintenance. The pipeline was

officially abandoned in 1996, 18 years after it was constructed. As part of abandonment, a

limited survey was undertaken which showed no apparent damage.

Pipelines buried beneath the seafloor could avoid damaging effects from ice. Methods for

installing pipelines beneath the seafloor by trenching include:

• Plowing - a device similar to a farmer's plow is pulled along the seafloor.

• Jet sledding - high pressure water jets are towed along the seafloor.
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DOI-MMS 18 Arctic IMPAK

• Conventional backhoe trenching - conventional backhoe equipment can be used from the 

sea ice surface.

Selection of a pipeline buried trench excavation method in the Alaskan Beaufort Sea would

depend upon water depth, time of year, length of pipeline, seafloor sediments, equipment

availability, and pipeline depth.

Another option would be to directionally drill and then pull pipe through the tunnel created.

Directionally drilled pipelines have been installed beneath large rivers and barrier islands. A

small diameter pilot hole is drilled, and a reamer attached and pulled back through the hole to

increase the diameter.

Offshore Buried Pipelines, Landfall Location Alternatives: The point where an offshore buried

pipeline intersects the coastline is called a pipeline landfall location. Pipeline landfall locations

may require onshore gravel pads to accommodate pipeline valves and leak detection equipment.

Equipment at these landfall locations would also require vehicular access, or a helipad.

Offshore Buried Pipelines, Corridor Alignments: The determination of offshore pipeline

alignments connecting an offshore oil and gas development/production facility with a pipeline

landfall location may consider environmental issues, construction cost, construction feasibility,

and obvious hazards.

1.8 FACILITY ABANDONMENT OR REUSE

When production ceases, facilities would be abandoned in accordance with terms of individual

leases. Abandonment could range from complete removal to a shut down mode with most

facilities left intact for future use. Requirement are decided when the field is abandoned because 

of the unknown future uses. Possible uses of an island structure include other oil and gas

projects, a deepwater port facility, scientific research projects, or a shelter for travelers. A

mobile production structure could be relocated for use at another reservoir. Pipelines are likely to 

be reused only if production continues, or to supply fuel for activities or housing. Housing

facilities on an island may be of interest to local government, businesses, or individuals.

If no uses for facilities can be identified, structures may be removed. Removal involves similar

activities to construction. Mobile production structures are easiest to remove, with islands and

pipelines the most difficult. Some facilities, (e.g., pipelines) could be abandoned in place.
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DOI-MMS 19 Arctic IMPAK

2 SELECTION OF ECONOMIC ACTIVITIES

In this chapter the most reasonable and likely set of technologies to be used in the Beaufort Sea

OCS are chosen. First, the available technologies are contrasted with the categorization of

activities contained in basic MMS projections of economic activity (numbers of wells drilled,

pipeline laid, etc.). Next, the most likely activities are selected. These primary activities are

then defined in terms of the secondary support activities required, including personnel transport, 

lodging, helicopter support, etc. Finally, a basic unit is chosen for selected activities (miles of

pipeline, number of barrels, etc.).

2.1 EXPLORATION AND DEVELOPMENT (E&D) SCENARIOS

MMS analysis of lease sales in all areas begins with the exploration and development (E&D)

scenarios. The first step economic model to be constructed in this study must be able to convert 

E&D inputs into the direct economic effects of the oil and gas development activities. These

direct impacts then become inputs to the second step model, which calculates indirect and

induced impacts. Therefore, it is crucial that the activities that are chosen to be modeled, and the 

measurement units that those activities are defined in terms of (i.e. miles of pipeline), are

consistent with the information provided in the E&D scenarios. This section focuses on the

consistency of potential activities with the E&D reports.

Exhibit 2-1 provides a reprint of a sample E&D report Lease Sale 195. As was the case for much 

of the preceding discussion of oil and gas production technology, the E&D scenarios are divided 

into three major phases (with each presented in the table on a separate page) including

exploration, development/production and transportation.
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DOI-MMS 20 Arctic IMPAK

EXHIBIT 2-1: SAMPLE E&D REPORT: REPRESENTATIVE DEVELOPMENT SCHEDULE FOR SALE 195

Combined

Exploration Production Offshore Oil Oil Oil

Exploration Delineation Drilling Production Production Injection Drilling Pipelines Production Production Production

Year Wells Wells Rigs Platforms Wells Wells Rigs (miles) (MMbbl) (MMbbl) (MMbbl)

2003

2004

2005

2006

2007 1 1 `

2008 1 1

2009 2 1

2010 1 1

2011

2012 2 2 1 3 3 1 10

2013 1 2 2 10 4 1 7.9 7.9

2014 2 1 10 4 1 15.7 15.7

2015 15.7 15.7

2016 1 3 3 1 30 15.7 15.7

2017 1 13 7 2 13.0 21.5 34.5

2018 20 8 2 10.7 28.6 39.4

2019 10 4 1 8.8 28.6 37.5

2020 7.3 28.6 35.9

2021 6.0 28.6 34.7

2022 5.0 28.6 33.6

2023 4.1 25.2 29.3

2024 3.4 22.2 25.6

2025 2.8 19.5 22.3

2026 2.3 17.2 19.5

2027 1.9 15.1 17.0

2028 13.3 13.3

2029 11.7 11.7

2030 10.3 10.3

2031 9.1 9.1

2032 8.0 8.0

2033 7.0 7.0

2034 6.2 6.2

2035 5.4 5.4

2036 4.8 4.8

2037

6 6 3 69 33 40 120 340 460

Exhibit 2-2 summaries the activities and units provided in a sample of E&D reports that were

reviewed. Note that the activities listed in the E&D report begin after seismic surveys and end

before abandonment. The E&D reports also does not address the effort expended on recovery 

activities or processing including whether the processing will take place onshore, offshore or

both. They do cover the major primary activities such as wells drilled, platforms installed,

lengths of pipelines constructed and oil produced. They generally also contain measures of some 

secondary or support activities such as helicopter flights, supply boat trips, tons of discharges,

and area surveyed.
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DOI-MMS 21 Arctic IMPAK

EXHIBIT 2-2: ACTIVITIES AND UNITS PROVIDED IN MMS E&D REPORTS

Phase Activity Unit

Exploration Well Drilling Number

Delineation Well Drilling Number

Drilling Discharges – Muds Short Tons

Drilling Discharges – Cuttings Short Tons

Helicopter Flights Number

Supply Boat Trips Number

Exploration

Shallow-Hazards Site Surveys Square km

Platform Installation Number

Production and Service Well Drilling Number

Total Production MMbbl

Peak Yearly Production MMbbl

Monthly Helicopter Flights Number

Monthly Supply Boat Trips Number

Drilling Discharges – Muds Short Tons

Drilling Discharges – Cuttings Short Tons

Development/Production

Shallow-Hazards Site Surveys Square km

Transportation Offshore Oil Pipeline Installation Km

Onshore Oil Pipeline Installation Km

The E&D reports also make some assumptions as to technology. For example, under product

transportation only pipelines are mentioned. Under exploration, no structures are mentioned. 

Under production, platforms are referred to, but since traditional platforms cannot be used in the 

Beaufort Sea, this term is probably used in a generic sense.

2.2 SELECTION OF MOST LIKELY TECHNOLOGIES

The discussions in the previous sections clearly indicate that there are a large number of potential 

technological alternatives for oil and gas activities. For example, approximately fifteen potential 

drilling structures were identified. Given the complexity of modeling the technologies, it is
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DOI-MMS 22 Arctic IMPAK

crucial to select the most likely technologies and to concentrate on modeling the production

functions and the economic impacts of those technologies.

Exhibit 2-3 provides a listing of the technical options for oil and gas activities in the Alaskan

Beaufort Sea. This exhibit was developed by combining a variety of tables and materials from

the Draft Beaufort Sea/Northstar EIS, supplemented by interviews conducted for this study. For 

each major activity, the table defines the alternate technologies, their characteristics, and the

reasons they were considered or eliminated. The technologies that were chosen for use in this

study are highlighted in underlined print.

The following is a summary listing of the chosen technologies:

• Drilling Method: Directional

• Seismic Surveys: From Ice

• Winter Exploration Structures: Ice Islands

• Summer Exploration Structures: Mobil Exploration Gravity Platforms

• Deep Water Exploration Structures: Exploration Drill Ships

• Shallow Water Development Production Structures: Manmade Gravel Islands

• Medium-Depth Water Development Production Structures: Bottom-Founded Platforms 

• Deep Water Development Production Structures: Sub-sea Development Wells

• Oil and Gas Recovery: Gas Cycling

• Oil Processing: Full Offshore Processing

• Product Transportation: Pipelines

• Abandonment: In Place

Originally only a single technology was chosen for each category of activity. However, MMS

requested enhancements to the model to allow more flexibility and to allow for analysis of

activities in deeper water that are forecasted to take place in the future. Ice islands represent the 

most favored technology at present but other options include mobile exploration gravity

platforms (SIDS, CIDS, SSDC, caisson, etc.), and drill ships were considered economical and

environmentally friendly options. Currently, ice islands are the favored technology, but as

exploration moves to deeper water, the use of alternate technologies will become more likely. 
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DOI-MMS 23 Arctic IMPAK

EXHIBIT 2-3: TECHNICAL OPTIONS FOR OIL AND GAS ACTIVITIES IN THE ARCTIC OCS

Phase Activities Reason For Consideration or Elimination

Drilling Methods · Directional Drilling Technology · Can access multiple bottom hole locations for single surface location.

· Vertical Drilling Technology · Only accesses reservoir directly beneath drilling location.

· Multiple drilling locations increases costs and environmental impacts.

Seismic Surveys · From Boat · Summer Only

· From Ice · Winter Only

· Lower environmental impact

Drilling 

Structures

· Onshore Drilling · To far from reservoir.

· Barrier Islands · Environmental value is too high.

· Bottom-founded Structures

- Caisson Retained Island(CRI) Designs 

and Tarsiut Island (Concrete CRI)

· Relocation difficult as caissons ballasted with sand.

· Redesign and construction of a new caisson structure would be very expensive.

· Owners proposed to modify to accommodate production facilities (22-35 wells).

- Concrete Island Drilling Structure 

(CIDS)

· Designed for arctic in water depths of 35 to 55 ft (10.6 to 16.8 m).

· Demonstrated long-term durability.

· High cost to convert to production facility.

- Mobile Arctic Caisson (Molikpaq) · Owners proposed to modify to accommodate production facilities (40 wells).

· Designed for arctic in water depths of 30 to 130 ft (9 to 39.6 m).

· Demonstrated durability.

· High cost to convert to production facility.

- Single Steel Drilling Caisson (SSDC) · Owners proposed to modify to accommodate production facilities (30-40 wells).

· Can operate in arctic in water depths of 25 to 100 ft (7.6 to 30 m).

· Demonstrated durability.

· High cost to convert to production facility.

- Manmade Gravel Islands · Proven technology, 17 constructed. in Beaufort Sea.

· Useful to approximately 50 ft (15.2 m) water depth.

· Can withstand high lateral load ice forces.

· Less expensive to design, construct, and maintain than other structures.

- Seafloor Templates · Usable in water depths over 200 ft (61 m) where ice gouging does not occur.

· Water depth too shallow.

- Subsea Silos · Unproven in Beaufort Sea but conceptual design addresses potential hazards.

· Caisson-protected subsea templates have been used in arctic

· High cost.

· Floating Structures

- Jackup Drilling Platforms · Not designed to operate in ice or support production.

· Could support summer exploration.

- Semi-Submersible Drilling Vessels · Not designed to operate in ice or support production.

· Could support summer exploration.

- Conventional Drillships · Not designed to operate in ice or support production.

· Could support summer exploration.

- Conical Drilling Unit (Kulluk) · Not designed to operate in ice or support production.

- Ice Islands · Melt in summer but low environmental impact and cost.
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DOI-MMS 24 Arctic IMPAK

EXHIBIT 2-3: TECHNICAL OPTIONS FOR OIL AND GAS ACTIVITIES IN THE ARCTIC OCS

Phase Activities Reason For Consideration or Elimination

· Supports winter exploration.

· Subsea Cavern · Unproven concept not yet demonstrated as technically or economically 

feasible.

· Sinkable Island Drill Ship (SIDS) · Demonstrated technology.

· Useful to approximately 50 ft.

· Demonstrated durability although suffers occasional ice damage

· Can be used year round.

· Extremely low environmental impact and cost

· Relatively easy to relocate

Oil and Gas 

Recovery

· Natural Blowdown (Primary Recovery) · Recovery rates of 5% to 20% are not economic.

· Usable on large reservoirs with difficulties implementing pressure 

enhancement.

· Secondary Recovery

- Gas Lift

· Effective if the reservoir contains heavy, thick oil or has high water content.

· Not appropriate because of composition of Northstar reservoir.

· Gas supply available in the Alaskan Beaufort Sea.

· Can be integrated with other recovery methods.

- Gas Cycling · Highest recovery rates of 45% to 65%.

· Can be integrated with other recovery methods.

· Useful for light oils that flow easily.

- Water Injection · Recovery rates of 35% to 45% are not economical.

· Can be integrated with other recovery methods.

- Waterflood · Recovery rates of 40% to 50%. (50% to 60%)

· Can be integrated with other recovery methods

· Best backup method.

· Enhanced (Tertiary) Recovery · Not considered because options are unknown.

Oil Processing · Full Offshore Processing · Secondary oil recovery techniques can be incorporated.

· Transport sales quality oil directly from production facility.

· Lowest environmental impact.

· Partial Offshore and Onshore 

Processing

· Difficult transportation of three-phase fluids by pipeline.

· Multiple locations increases environmental impact.

· Full Onshore Processing · Offshore production structures can be smaller.

· Difficult transportation of three-phase fluids by pipeline.

· Environmental impacts too high onshore.

Product 

Transportation

· Tankers and Barges · Greater spill risk.

· High cost for facilities and dredging.

· Pipeline on a Gravel Causeway · Provides protection of pipeline and access for maintenance.

· Negative environmental impacts

· High cost for bridges.

· Pipeline Buried Beneath Seafloor · Avoids damaging effects from ice.

· Safest option with lowest impact

· Pipeline Installed on Seafloor · Risk of damage or rupture from ice.

· Can be used only in water depths over 200 ft (61 m).

· Elevated Pile-supported Structure · Would be exposed to winds, wave action, and ice forces.

· Structure could impede passage of vessels/barges.
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DOI-MMS 25 Arctic IMPAK

EXHIBIT 2-3: TECHNICAL OPTIONS FOR OIL AND GAS ACTIVITIES IN THE ARCTIC OCS

Phase Activities Reason For Consideration or Elimination

Spoil Disposal · Onshore · Saline material kills terrestrial vegetation.

· Shallow water · Sediments block water circulation and navigation.

· Outside Barrier Islands · Achieves good dispersion of waste material.

· Does not impede water circulation or navigation.

Abandonment · In Place · Preserves key facilities for reuse and shelfer.

· Removal · Returns environment closer to original state.

Notes: ft = Foot or Feet

Km = Kilometer(s)

m = Meter(s)

% = Percent

TAPS = Trans Alaska Pipeline System

Construction of alternate data for seismic surveys on ice and by boat were also considered, but

given the relatively small size of this activity it was not deemed worth while to do so as the

economic differences are not significant. However, it is recognized that both methods of seismic 

surveys are likely. Gravel islands, full offshore processing and pipeline transport were clearly

superior both technologically and environmentally when compared to other current options.

However, as production moves to deeper waters the slope requirements and the resulting size of

the islands gravel islands will make them prohibitively expensive. As a result, bottom founded

platforms might be expected to replace gravel islands once water depths reach over 15 meters

and sub-sea wells would replace bottom founded platforms once water depths reach over 35

meters.

2.3 SELECTION OF ECONOMIC ACTIVITIES FOR MODELING

Many of the economic activities associated with oil and gas production share common elements 

such as well drilling, seismic surveys, ice road construction, spoils disposal, headquarters

support, etc. Since the labor, material and equipment inputs to these secondary or support

activities are similar across the more primary activities, it is advantageous to separate these

components from the primary activities.

Exhibit 2-4 provides a listing of what were considered primary activities. Twenty-one activities 

are listed in roughly chronological order. Note that the construction and operation of facilities

are separated, as operation often continues several years. The primary activities include:

• Seismic Surveys on Ice

• Construction of an Ice Exploration Island

• Movement of a Drill Ship or Bottom Founded Platform
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DOI-MMS 26 Arctic IMPAK

• Operation of an Exploration Drill Ship in Calm Waters

• Operation of an Exploration Drill Ship in Rough Waters

• Operation of a Mobil Exploration Gravity Platform

• Drill Exploration Well

• Construction of a Gravel Production Island - Place Gravel

• Construction of a Gravel Production Island - Install Erosion Protection Systems

• Installation of Processing, Recovery and Other Production Island Equipment

• Drill Production Well

• Production and Operation Including Processing, Recovery and Pumping

• Construction of a Small Gas Only Production Facility

• Operation of a Small Gas Only Production Facility

• Construction of Offshore Pipelines

• Construction of Onshore Pipelines

• Construction of Sea Floor Pipelines

• Perform Well Workover

• Landbase Operations

• Spill Contingency

• Abandonment

Also included in Exhibit 2-4 is a listing of the secondary or support activities. Five of these

activities have been identified including:

• North Slope Support

• General Personnel Transport

• Ice Roads

• Helicopter support

• Barge support

It is important to rigorously define each activity to insure that there is no double counting. It is

also important to ascertain whether the secondary activity varies depending on the primary

activity it is associated with. For example, there are differences between ice roads used during

construction and the ice roads used during the normal operating phase. This is because ice roads 

during construction need to handle a bigger load and therefore need to be thicker. 

The primary and secondary activities are structured so that if a unit of primary activity is

stimulated, a predetermined amount of the required secondary activities are stimulated. For

example, if a production island is in operation, a certain amount of helicopter support flights will 

occur. The number of helicopter flights will vary based on certain aspects of the scenario, such

as the distance of the project from shore and the number of islands in operation.
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DOI-MMS 27 Arctic IMPAK

EXHIBIT 2-4: PRIMARY AND SECONDARY ACTIVITIES - DRIVERS AND DEFAULT FACTORs

Secondary Activities

Primary Activities

2.

North

Slope

Support

3.

General

Personnel

Transport

4.

Ice

Roads

10.

Helicopter

Support

11.

Barge

Support

Units

Per 300 

Person 

Camp 

Per Year Per Day

Per 10 

Miles Per Day Per Day

1. Survey on Ice Per Month X

5. Ice Exploration Island Per Island X X X X

6. Move Drill Ship/Platform Per Day X

7. Operate Drill Ship in Calm Waters Per Day X X

8. Operate Drill Ship in Rough Waters Per Day X X

9. Operate Mobile Exploration Platform Per Day X X X

12. Exploration Wells Per Well X X X

13. Production Wells Per Well X X X

14. Well Workover Per Workover XX X

15. Place Gravel Island Per Cubic Yard X X X

16. Gravel Island Protection Per Island X X X X

17. Equip Production Island Per Island X X X X X

18. Operate Production Island Per Year XX X X X

19. Construct Gas Production Facility Per Facility X X

20. Operate Gas Production Facility Per Year X X

21. Construct Offshore Pipeline Per Ten Miles X X X

22. Construct Onshore Pipeline Per Ten Miles X X X

22. Lay Sea Floor Pipeline Per Ten Miles X X X X

24. Landbase Operations Per Year X XX

25. Spill Contingency Per Year X X

26. Abandonment in Place Per Island X X X X
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DOI-MMS 28 Arctic IMPAK

2.4 UNITS

In order to model the impacts of a particular oil and gas development it is necessary to have

estimates of the size of the development. These estimates, such as the E&D scenarios provided

in Exhibit 2-1, define the development in terms of number of wells, miles or kilometers of

pipelines, etc. Exhibit 2-4 also provides units for the majority of the activities. These units were 

designed to be as compatible as possible with the E&D scenarios. At the same time they need to 

match with the engineering and cost data that are available. A glance at the data provided in

Appendix A of the Draft Beaufort Sea/Northstar EIS clearly indicates that all units are in inches, 

feet and miles. Therefore, all estimates are in customary U.S. measures.

2.5 GEOGRAPHIC AREAS

The original purpose of the IMPAK research was is to model the economic impact of Beaufort

Sea OCS development. The original study focused on existing proven technologies used in that

area. The analysis was later extended to the sub-arctic in a parallel but separate study. Also

included was the development of a simplified model based on both studies that could be used to 

model the costs of local gas production and processing. In this version of the Artic IMPAK

model, additional technologies were added that allow the modeling of the impacts of oil and gas 

developments that might occur in the future using emerging technologies in deep sea areas. One 

such area for which no specific model was built, but in which MMS is interested, is the Chukchi 

Sea/Hope Basin.

MMS had originally requested that the study provide a rough rule of thumb to the effect that

costs in that part of the Arctic OCS would require a certain percentage adjustment for all

manpower and costs. According to engineering study staff, their best estimate is that a factor of 

two over traditional Beaufort Sea OCS development technologies could be used to estimate

costs. However, the deep water technologies that have been added in the latest iteration of the

model allow for a more accurate approach. Drilling in these areas would be conducted using a

drill ship in rough seas (Activity 8). Note that the necessary supporting activities are all mileagebased including moving the drill ship (Activity 6), helicopter support (Activity 10), barge

support (Activity 11), and sea floor pipelines (Activity 23). Most of the other activities do not

require mileage adjustments and their cost do not vary by location including geological survey

(Activity 1), well drilling and workovers (Activities 12 through 14), island operations (Activity

18), and abandonment (Activity 26). The only potential problem is if a new landbase is

constructed. This is because the model assumes that existing facilities in Barrow will be used. 

Several activities include only operating costs including north slope support (Activity 2), land

base operations (Activity 24) and spill contingency (Activity 25). However, in most

circumstances, engineering study staff believes that the use of Barrow as the landbase is the most 

likely scenario.
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DOI-MMS 29 Arctic IMPAK

3 MODELS AND MODELING APPROACHES

The purpose of this chapter is to examine alternative modeling processes for determining the

economic impact of Beaufort Sea OCS development. The chapter begins with an examination of 

the modeling issues that arise due to the unique aspects of Beaufort Sea OCS development. 

Next, the three key economic models are reviewed followed with shorter synopses of a few

additional models. The three key models include the Manpower model, the Rural Alaska Model 

(RAM) and IMPLAN. The basic purpose and functions of the models are reviewed and their

strengths and weaknesses are analyzed. The chapter closes with two sections, the first of which

discusses the current modeling approach. The second proposes some alternatives and identifies

the preferred alternative.

3.1 MODELING ISSUES

Activities associated with the exploration and development of oil reserves generate employment

and income for workers employed in those activities. In economics these types of consequences 

are often termed direct impacts. The total economic impact on the regional economy includes

not only these direct economic impacts, but also what economists refer to as indirect impacts. 

Indirect impacts refer to the jobs and earnings created in industries that support the primary 

exploration and development activities. These impacts might include, for example, additional

jobs resulting from increased transportation related to E&D activities such as ferrying workers

to/from platforms or from southern to northern Alaska. Finally, employees spend part of their

earnings that were originally generated either directly or indirectly from the E&D activities. 

These expenditures give rise to induced impacts, which are defined in economics as the

additional employment and income generated as a result of this spending.

From an economic standpoint, oil and gas exploration and development activities in the Beaufort 

Sea are unique. The economic impacts are the direct result of a large, but relatively short-term, 

natural resource extraction activity that is based on new and innovative technologies. This

activity is supported by boomtown like small towns and various support industries providing

transportation and other services and infrastructure. These activities are all overlaid upon a low 

technology culture that relies, in the long-term, upon the land, the natural wildlife and a set of

non-western traditional knowledge and skills.

In some sense, the success of OCS development will be judged by how little damage is done to

the environment. It is an almost ironic juxtaposition to traditional economic development that

the criterion for success should be how little evidence of the intrusion of man is left when the oil 

fields are abandoned.

As is the case with mining towns, the long-term economic development effects are, in part, the

development of infrastructure. In the case of North Slope oil development activities, these

effects include items such as roads, airports, utilities, governmental structures, gravel islands
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DOI-MMS 30 Arctic IMPAK

with shelters, and other facilities that can be used by residents either during or after the oil and

gas related activities. Other economic effects include the jobs, income and spending generated

during the actual exploration, development and production phases. Also included are the income 

provided through royalty payments for near shore projects shared with Alaska by the Federal

Government.

The sum of impacts depends to a large extent on the number of interacting industries in the study 

area. This number is heavily influenced by the physical size of the geographic area under

consideration. The impacts tend to increase with increases in the size of the region. It can be

seen, therefore, that the quantity of impacts measured depends upon the definition of the study

area and can vary significantly depending on whether the vantage point is at the county

(boroughs in Alaska), state or national level. In many cases, it is useful to be able to isolate the

impacts that accrue to different geographic levels. Having a single consistent model for this

purpose ensures that different impact magnitudes are the result of different geographic

absorption rates rather than differences in model assumptions. 

In all cases it is important to take into consideration all of the regional impacts that will result

from the stimulus. The size of the geographic area may also influence this consideration. For

example, the direct impacts on a small region may be less than the direct impacts on a larger

region. This can happen if the smaller area lacks industries which are present in the larger area. 

Another example highlights what can happen if a stimulus is simply transferred from one area to 

another area. Consider a manufacturing plant that moves from one county in a state to a different 

county in the same state. At the county level, the old county will experience negative impacts

(e.g., job losses) whereas the new county will experience positive impacts. At the state level, the 

net impacts may be zero or very small since the gains in one county are offset by losses in

another county.

Economic activity often includes unintended or non-priced effects or byproducts. For example, 

automobile use creates air pollution while OCS oil and gas production involves the potential for 

spills and the disruption of natural ecosystems. Economists refer to these non-market impacts as 

externalities. The costs of externalities can be internalized. Examples in the Arctic OCS include 

spill contingency operations and abandonment activates. To the extent externalities are

internalized they are included in the economic impacts measured by Arctic IMPAK. To the

extent impacts are not internalized, such as any spilled oil that is not recovered, the economic

impacts are not quantified in the model.

In assessing economic activities, it is often desirable to consider the distribution of impacts

across socio-economic groups or generations. For example, for the economic impacts considered 

in this study, it will be interesting to determine the proportion of those filling high skill, high

paying jobs that will leave the area after they have completed short term work assignments with 

those who stay. It will also be interesting to determine what the fate will be for Alaska Natives. 

When the development and production has been completed there may not be work on this kind

left in the local area. Alaska Natives may be left with the choice of moving to find similar

skilled or semi-skilled work or change to some other cash job. Another choice may be to return 
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DOI-MMS 31 Arctic IMPAK

to their village and rely on traditional subsistence. Returning to this lifestyle may be difficult

because subsistence hunting skills may be diminished or difficult to readjust to.

Therefore, while OCS economic activities create jobs and income, these impacts, as discussed in 

the preceding paragraphs, should be considered in light of transfers, externalities and

distributional impacts. In this study, attempts will be made, where practical, to consider these

issues or to point out modeling approaches that might facilitate consideration of these issues. For 

example, use of the IMPLAN model allows impacts to be calculated by region and by socioeconomic group. This advantage of this model is worth highlighting.

Finally, while the purpose of this study is to examine and develop tools to measure economic

impacts, it is important to differentiate between “impacts” and “benefits.” Impacts are merely a

measure of the amount of economic activity and can be defined in terms of jobs, income or

expenditures. An economic benefit, on the other hand, is traditionally defined as a change in

consumer surplus, or a return that can not be attributed to a resource or factor of production.

3.2 THE MANPOWER MODEL

The Manpower Model was created in the late 1970's and refined in the early 1980's to project the 

number of workers directly employed in proposed OCS exploration, development, and

production activities. These data have historically been used in other models to predict

secondary employment and population. The employment data from the Manpower Model and

the secondary employment and population data are used in Environmental Impact Statements.

The employment factors in the Manpower Model are based on information, no more current than 

the early 1980's, from industry on the actual number of workers used for 20 work units covering 

a range of activities from exploration and development to production. Unfortunately, no

documentation of the methodology or sources used to construct the model are available.

For the most part, it is fairly certain that the employment factors in the Manpower Model are no 

longer valid. Since the early 1980's, technology has changed to the extent that the input

variables should be reexamined and adjusted. Moreover, the current Manpower Model has one

set of activities and labor factors for all of Alaska. These units and labor factors were developed 

based on activities for the more southern portions of Alaska and are not readily applicable to

Arctic operations. For example, the current model assumes that platforms will be the primary

technology, while such structures cannot withstand the ice forces in arctic environments.

The Manpower Model is a spreadsheet model that is divided into three main parts. The first part 

contains the labor factors that were collected. The second part contains projections of manpower 

by work units and tasks. The third part contains projections of manpower by job type. The

portions of the model that contain the projections are linked to and are based upon the labor

factors.
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Structure of the Manpower Model

The current manpower model estimates petroleum industry related employment generated from

exploration, development and production activities. These activities are defined in terms of the

units and tasks listed in Exhibit 3-1.

Exhibit 3-1: Unit and Task Descriptions

UNIT Unit Description TASK Task Description

UNIT 1 Number of Exploration and Delineation Wells Drilled Task 1 Drilling Crew Activities

Task 1A Helicopter Support for Drilling

Task 1B Supply/Anchor Boats for Drilling Support

Task 1C Longshoring Support for Drilling

Task 1D Other Onshore Work in Support of Drilling

UNIT 2 Number of Exploration Shore Bases Constructed Task 2 All Shore Base Construction Activities

UNIT 3 Number of Exploration Shore Bases Constructed Task 3 All Base Operations (Except Tasks 1A - 1D)

UNIT 4 Number of Geophysical or Geological Surveys Conducted Task 4 All Work by Survey and Boat Crews

UNIT 5 Number of Exploration Islands Constructed Task 5 All Island Construction Activities

UNIT 6 Number of Production Platforms and Equipment Installed Task 6 All Work by Platform Installation Crews

Task 6A Helicopter Support-Platform Installation

Task 6B Tugboat Support for Platform Installation

Task 6C Supply/Anchor Boat Support for Platform Installation

Task 6D Longshoring for Platform Installation

Task 6E Other Onshore Support for Platform Installation

UNIT 7 Number of Offshore Loading Platforms Installed Task 7 All Work by Platform Installation Crews

Task 7A Helicopter Support for Platform Installation

Task 7B Tugboat Support for Platform Installation

Task 7C Supply/Anchor Boat Support for Platform Installation

Task 7D Longshoring for Platform Installation

Task 7E Other Onshore Support for Platform Installation

UNIT 8 Number of Production Shore Bases Constructed Task 8 All Shore Base Construction Activities

UNIT 9 Number of Production or Service Wells Drilled Task 9 All Work of the Drilling Crews

UNIT 10 Offshore Oil Pipe Layed (100's of Miles) Task 10 All Work of the Laying Barge Crews

Task 10A Helicopter Support for Pipe Laying

Task 10B Tugboat Support for Pipe Laying

Task 10C Supply/Anchor Boats for Pipe Laying

Task 10D Longshoring Support for Pipe Laying

Task 10E Other Onshore Support for Pipe Laying

UNIT 11 Onshore Oil Pipe Layed (100's of Miles) Task 11 All Pipeline Laying and Related Activities

UNIT 12 Number of Marine Oil Terminals Constructed Task 12 All Related Activities

UNIT 13 Number of Onshore Oil Pump Stations Constructed Task 13 All Related Activities

UNIT 14 Number of Production Islands Constructed Task 14 All Related Activities

UNIT 15 Number of Production Platforms Operating Task 15 All Work of Platform Operations Crews

Task 15A Helicopter Support for Platform Operations

Task 15B Supply/Anchor Boats for Platform Operations

Task 15C Longshoring for Platform Operations

Task 15D Other Onshore Work for Platform Operations

UNIT 16 Number of Major Platform Maintenances Performed Task 16 All Work of Platform Maintenance Crews

UNIT 17 Number of Production Island Maintenances Task 17 All Work of Island Maintenance Crews

UNIT 18 Number of Production or Service Well Workovers Task 18 All Work of Workover Crews

UNIT 19 Number of Production Shore Bases Operating Task 19 All Base Operations

UNIT 20 Number of Marine Oil Terminals Operated Task 20 All Terminal Operations Activities

The model itself already contains labor factors in the form of estimates of labor requirements per 

unit of activity. These factors are stimulated by entering into the model estimates of the amounts 

or numbers of each activity that will take place as a result of the lease sale or other governmental 
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DOI-MMS 33 Arctic IMPAK

action under examination. The combination of these estimates of the amounts or numbers of

each activity is referred to by the Minerals Management Service (MMS) as an Exploration and

Development (E&D) scenario. Such scenarios are hypothesized outside of the model and

comprise the main inputs into the Manpower Model, which then uses them to calculate two

primary outputs: (1) petroleum related employment generated in Alaska by place of residence,

and (2) petroleum related employment generated in the study area (in this case, the North Slope

Borough).

The internal calculations can be divided into five levels, each with one to five steps, as depicted

schematically in Exhibit 3-2 and described below.
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Level I: Input Parameters

This level of the model includes primarily a variety of data that provide the inputs or parameters 

to the modeling procedure. These estimates are developed outside of the model. Some are

specific inputs to a particular model run and some are the basic parameters of the model that

would change only if the model were updated or refined.

• Step I.A.: Calculate Total Man-Months Per Task Per Unit

For each unit and task, this step provides the input values for and calculates the product of the 

following variables: task crew size, number of shifts, number of rotations, number of tasks per

unit, and duration of the task in months. The estimates for these variables were developed

outside of the model and are used as model parameters. Both the variables and the resulting

product are assumed to remain constant over the forecast horizon.

• Step I.B.: Forecast Number of Units

These forecasts are estimated outside of the model. As discussed above they are developed from 

an E&D Scenario. The forecast numbers of units are used as model inputs. Forecasts for the

following units are provided including:

1) Exploration & delineation wells drilled

2) Exploration shore bases constructed

3) Exploration shore bases operating

4) Geophysical-Geological surveys conducted

5) Exploration islands constructed

6) Production platforms and equipment installed

7) Offshore loading platforms installed

8) Production shore bases constructed

9) Production or service wells drilled

10 Hundreds of miles of offshore oil pipe laid

11) Hundreds of miles of onshore oil pipe laid

12) Terminals constructed

13) Onshore oil pump stations constructed

14) Production islands constructed

15) Production platforms operating

16) Major platform maintenance operations performed

17) Production island maintenance operations performed

18) Production or service well workovers

19) Production shore bases operating

20) Marine oil terminals operating
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DOI-MMS 35 Arctic IMPAK

Generally the E&D scenario contains forecasts for a few of the above items and the remaining

items are based on certain “rules of thumb.” For example, islands are assumed to require

maintenance after a certain number of years.

• Step I.C.: Estimate Percent of Out-of-State Commuters by Task

For each unit and task, an estimate of the percentage of the jobs held by out-of-state commuters 

is provided in the model. The estimates for this variable were developed outside of the model

and are used as model parameters. The estimates for this variable are assumed to remain

constant over the forecast horizon.

• Step I.D.: Forecast Employment at Headquarters

Estimates of employment at headquarters are developed outside of the model. Because these

estimates are forecast outside of the model, the numbers are not necessarily related to the number 

of units forecast.

• Step I.E.: Estimate Residential Distribution of Alaskan Petroleum Related Employment

The estimates of the residential distribution of Alaskan petroleum related employment are

developed outside of the model and are used to distribute Alaskan residents who work in the

petroleum industry to geographic residential locations in Alaska. The percentages are used as

model inputs and are held fixed over the forecast horizon. The residential areas and percentages 

used include Anchorage (63.2%), Fairbanks Census Division (6.4%), South Central Alaska

Region1 (22.2%), and the rest of Alaska (8.2%). 100% of the people who work at headquarters 

are assumed to live in Anchorage.

Level II: Forecasts by Task

In this level, the estimates of the amount of labor to complete a task are multiplied by the

forecasts of the number of times the task will be performed in each year to provide a forecast of

labor by year for each task.

• Step II.A.: Forecast Total Man-Months by Task

This step calculates the product of Step I.A (Total Man-Months per Task per Unit) and Step I.B

(Forecast Number of Units), producing a forecast time series of total man-months by task. For

example, it is estimated in Step I.A that conducting a geophysical-geological survey will require 

 

1

Includes the following 1970 census divisions: Matanuska-Susitna, Valdez-Chtina-Whittier, 

Cordova-McCarthy, Seward, Kenai-Cook Inlet, and Kodiak. This does not include the

municipality of Anchorage which is usually considered a part of the South Central Alaska

Region.
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DOI-MMS 36 Arctic IMPAK

150 man-months and in Step I.B that one survey will be required in year 2003. As a result, the

forecast is that for that task 150 man-months of work will be required.

Level III: Man Year Forecasts

In this level, the forecasted estimates of manpower by task are combined in several tabulations

including activities, locations, terms, skill levels, parts and groups. These tabulations are

divided, for discussion purposes, into three main steps with activities, locations, terms, and skill

levels as the first group, parts as the second and groups as the third.

• Step III.A.: Calculate Total Man-Years by Major Activity (Mining, Construction, Air

Transportation, Marine Transportation), Location (Onshore/Offshore), Employment Term

(Short-term/Long-term), and Skill Level (skilled/unskilled)

This step converts the total man-months by task forecast (calculated in step II.A) into a forecast

of man-years by major activity, onshore/offshore location, length of employment, and skill level.

The conversion is based on an assignment of each task to a major activity (mining, construction, 

air transportation, or marine transportation), an onshore or offshore location, a short-term or

long-term task, and a skill level (skilled or unskilled)2. These assignments are specified in the

program's aggregation formulas and are not easily modified by the user. The task assignments

are shown in Exhibits 3-3 and 3-4. Exhibit 3-3 presents assignments by task while Exhibit 3-4 

presents tasks by assignment. Note that tasks 2 and 8 do not have any assignments. As there is 

no documentation for the model there is no indication as to why these tasks were not assigned

and no logical reason was evident.

 

2

 Four of the tasks (11, 12, 13, and 15) divide the total task manpower estimate between skilled

and unskilled labor rather than just assigning it to one of the categories.
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DOI-MMS 37 Arctic IMPAK

UNIT Unit Description TASK Task Description Major Activity Location Term Skill Level

UNIT 1 Number of Exploration and Task 1 Drilling Crew Activities Mining Off-Shore Short Term Skilled

Delineation Wells Drilled Task 1A Helicopter Support for Drilling Air Transportation On-Shore Short Term Skilled

Task 1B Supply/Anchor Boats for Drilling Support Marine Transportation Off-Shore Short Term Skilled

Task 1C Longshoring Support for Drilling Marine Transportation On-Shore Short Term Unskilled

Task 1D Other Onshore Work in Support of Drilling Mining On-Shore Short Term Skilled

UNIT 2 Number of Exploration Task 2 All Shore Base Construction Activities

Shore Bases Constructed

UNIT 3 Number of Exploration Task 3 All Base Operations (Except Tasks 1A - 1D) Mining On-Shore Short Term Unskilled

Shore Bases Constructed

UNIT 4 Number of Geophysical or Task 4 All Work by Survey and Boat Crews Mining Off-Shore Short Term Skilled

Geological Surveys Conducted

UNIT 5 Number of Exploration Task 5 All Island Construction Activities Construction Off-Shore Short Term Unskilled

Islands Constructed

UNIT 6 Number of Production Platforms Task 6 All Work by Platform Installation Crews Mining Off-Shore Short Term Skilled

and Equipment Installed Task 6A Helicopter Support-Platform Installation Air Transportation On-Shore Short Term Skilled

Task 6B Tugboat Support for Platform Installation Marine Transportation Off-Shore Short Term Skilled

Task 6C Supply/Anchor Boat Support for Platform Installation Marine Transportation Off-Shore Short Term Skilled

Task 6D Longshoring for Platform Installation Marine Transportation On-Shore Short Term Unskilled

Task 6E Other Onshore Support for Platform Installation Mining On-Shore Short Term Skilled

UNIT 7 Number of Offshore Loading Task 7 All Work by Platform Installation Crews Mining Off-Shore Short Term Skilled

Platforms Installed Task 7A Helicopter Support for Platform Installation Air Transportation On-Shore Short Term Skilled

Task 7B Tugboat Support for Platform Installation Marine Transportation Off-Shore Short Term Skilled

Task 7C Supply/Anchor Boat Support for Platform Installation Marine Transportation Off-Shore Short Term Skilled

Task 7D Longshoring for Platform Installation Marine Transportation On-Shore Short Term Unskilled

Task 7E Other Onshore Support for Platform Installation Mining On-Shore Short Term Skilled

UNIT 8 Number of Production Shore Task 8 All Shore Base Construction Activities

Bases Constructed

UNIT 9 Number of Production or Task 9 All Work of the Drilling Crews Mining Off-Shore Short Term Skilled

Service Wells Drilled

UNIT 10 Offshore Oil Pipe Layed Task 10 All Work of the Laying Barge Crews Mining Off-Shore Short Term Skilled

(100's of Miles) Task 10A Helicopter Support for Pipe Laying Air Transportation On-Shore Short Term Skilled

Task 10B Tugboat Support for Pipe Laying Marine Transportation Off-Shore Short Term Skilled

Task 10C Supply/Anchor Boats for Pipe Laying Marine Transportation Off-Shore Short Term Skilled

Task 10D Longshoring Support for Pipe Laying Marine Transportation On-Shore Short Term Unskilled

Task 10E Other Onshore Support for Pipe Laying Mining On-Shore Short Term Skilled

UNIT 11 Onshore Oil Pipe Layed Task 11 All Pipeline Laying and Related Activities Construction On-Shore Short Term 40% Skilled, 60% Unskilled

(100's of Miles)

UNIT 12 Number of Marine Oil Task 12 All Related Activities Construction On-Shore Short Term 20%Skilled, 80% Unskilled

Terminals Constructed

UNIT 13 Number of Onshore Oil Task 13 All Related Activities Construction On-Shore Short Term 20%Skilled, 80% Unskilled

Pump Stations Contstructed

UNIT 14 Number of Production Islands Task 14 All Related Activities Construction Off-Shore Short Term Unskilled

Constructed

UNIT 15 Number of Production Task 15 All Work of Platform Operations Crews Mining Off-Shore Long Term 90% Skilled, 10%Unskilled

Platforms Operating Task 15A Helicopter Support for Platform Operations Air Transportation On-Shore Long Term Skilled

Task 15B Supply/Anchor Boats for Platform Operations Marine Transportation Off-Shore Long Term Skilled

Task 15C Longshoring for Platform Operations Marine Transportation On-Shore Long Term Unskilled

Task 15D Other Onshore Work for Platform Operations Mining On-Shore Long Term Skilled

UNIT 16 Number of Major Platform Task 16 All Work of Platform Maintenance Crews Mining Off-Shore Long Term Skilled

Maintenances Performed

UNIT 17 Number of Production Task 17 All Work of Island Maintenance Crews Construction Off-Shore Short Term Unskilled

Island Maintenances

UNIT 18 Number of Production or Task 18 All Work of Workover Crews Mining Off-Shore Long Term Skilled

Service Well Workovers

UNIT 19 Number of Production Task 19 All Base Operations Mining On-Shore Long Term Unskilled

Shore Bases Operating (Except tasks related to Units 6, 7, 10, and 15)

UNIT 20 Number of Marine Oil Task 20 All Terminal Operations Activities Mining On-Shore Long Term Skilled

Terminals Operated

Exhibit 3-3: Activity, Location, Term, and Skill Level Assignments by Task
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DOI-MMS 38 Arctic IMPAK

Major Activity Location Term Skill Level Tasks

Mining On-Shore Short Term Skilled 1D, 6E, 7E, 10E

Unskilled 3

Long Term Skilled 15D, 20

Unskilled 19

Off-Shore Short Term Skilled 1, 4, 6, 7, 9, 10

Unskilled Blank

Long Term Skilled 90% of 15, 16, 18

Unskilled 10% of 15

Construction On-Shore Short Term Skilled 40% of 11, 20% of 12, 20% of 13

Unskilled 60% of 11, 80% of 12, 80% of 13

Long Term Skilled Blank

Unskilled Blank

Off-Shore Short Term Skilled Blank

Unskilled 5, 14, 17

Long Term Skilled Blank

Unskilled Blank

Air On-Shore Short Term Skilled 1A, 6A, 7A, 10A

Transportation Unskilled Blank

Long Term Skilled 15A

Unskilled Blank

Off-Shore Short Term Skilled Blank

Unskilled Blank

Long Term Skilled Blank

Unskilled Blank

Marine On-Shore Short Term Skilled Blank

Transportation Unskilled 1C, 6D, 7D, 10D

Long Term Skilled Blank

Unskilled 15C

Off-Shore Short Term Skilled 1B, 6B, 6C, 7B, 7C, 10B, 10C

Unskilled Blank

Long Term Skilled 15B

Unskilled Blank

Exhibit 3-4: Aggregation of Task Man-Months in Step 3A

• Step III.B.: Calculate Total Man-Months by Part

In this step, the forecast of man-months by task (generated in step II.A.) are aggregated into three 

categories or "parts." No titles or definitions of the individual “parts” are provided and no

reasons why they are calculated is given. Part 1 is the sum of the man-months associated with

units 1-8; Part 2 is the sum of the man-months associated with units 9-15; Part 3 is the sum of the 

man-months associated with units 16-20. The forecast time series produced in this step do not

feed into any other steps.
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DOI-MMS 39 Arctic IMPAK

• Step III.C.: Calculate Total Non-Resident Man-Months by Group

In this step, the number of man-months performed by non-resident workers are estimated for

each task and then aggregated into seven “groups.” No titles or definitions of the individual

“groups” are provided and no reasons why they are calculated is given. The number of manmonths associated with non-resident workers is estimated by taking the product of the outputs

generated in steps I.C. and II.A. above. The aggregation scheme is as follows: Group 1 includes

all tasks in units 1-4; Group 2 includes all tasks under unit 5-6, plus task 7 under unit 7; Group 3 

includes tasks 7A - 7E under unit 7, plus all tasks under unit 8-9; Group 4 includes all tasks

under units 10-11; Group 5 includes all tasks under units 12-14, plus Task 15 and Task 15A

under unit 15; Group 6 includes tasks 15B-15D, plus all tasks under units 16-17; Group 7

includes all tasks under units 18-20.

Level IV Man Years by Location and Industry

In this level, the forecasted estimates of manpower are combined in several tabulations in a

similar manner to Level III. At this level, however, tabulations also include a dimension for the 

industry the manpower is associated with. In one step, manpower is developed for the Arctic

only with detail by industry, location, term and skill level. In a second step, total manpower by

industry is calculated, with headquarters employment added in.

• Step IV.A.: Calculate Arctic Community Man Years by Industry (Air Transportation, Marine 

Transportation, Island), Location (Onshore/Offshore), Employment Term (Short-term/Longterm), and Skill Level (skilled/unskilled)

This step distributes each task's total manpower forecast to various industry, onshore/offshore

location, employment term, and skill-level categories. It also specifies whether or not the jobs

associated with a particular task are located in the Arctic community. For most tasks one

hundred percent of the jobs are assumed to be located in the Arctic community; however, one

hundred percent of the jobs associated with tasks 5, 14, and 17 are assumed to be located

elsewhere. Distribution of task manpower to jobs located in the community is shown in Exhibit

3-5. These distributions are specified in the program's aggregation formulas and are not easily

modified by the user. The percentages used to distribute the manpower are assumed to remain

constant over the forecast horizon. The forecasts generated in this step do not feed into any other 

steps.
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UNIT Unit Description TASK Task Description Industry Location Term

UNIT 1 Number of Exploration and Task 1 Drilling Crew Activities Marine Transportation Off-Shore Short Term

Delineation Wells Drilled Island Off-Shore Short Term

Task 1A Helicopter Support for Drilling Air Transportation On-Shore Short Term

Task 1B Supply/Anchor Boats for Drilling Support Marine Transportation Off-Shore Short Term

Task 1C Longshoring Support for Drilling Marine Transportation On-Shore Short Term

Task 1D Other Onshore Work in Support of Drilling Marine Transportation On-Shore Short Term

Island On-Shore Short Term

UNIT 2 Number of Exploration Task 2 All Shore Base Construction Activities Air Transportation On-Shore Short Term

Shore Bases Constructed Marine Transportation On-Shore Short Term

Island On-Shore Short Term

UNIT 3 Number of Exploration Task 3 All Base Operations (Except Tasks 1A - 1D) Air Transportation On-Shore Short Term

Shore Bases Constructed Marine Transportation On-Shore Short Term

Island On-Shore Short Term

UNIT 4 Number of Geophysical or Task 4 All Work by Survey and Boat Crews Marine Transportation Off-Shore Short Term

Geological Surveys Conducted Island Off-Shore Short Term

UNIT 5 Number of Exploration Islands Constructed Task 5 All Island Construction Activities

UNIT 6 Number of Production Platforms Task 6 All Work by Platform Installation Crews Marine Transportation Off-Shore Short Term

and Equipment Installed Island Off-Shore Short Term

Task 6A Helicopter Support-Platform Installation Air Transportation On-Shore Short Term

Task 6B Tugboat Support for Platform Installation Marine Transportation Off-Shore Short Term

Task 6C Supply/Anchor Boat Support for Platform Installation Marine Transportation Off-Shore Short Term

Task 6D Longshoring for Platform Installation Marine Transportation On-Shore Short Term

Task 6E Other Onshore Support for Platform Installation Marine Transportation On-Shore Short Term

Island On-Shore Short Term

UNIT 7 Number of Offshore Loading Task 7 All Work by Platform Installation Crews Marine Transportation Off-Shore Short Term

Platforms Installed Island Off-Shore Short Term

Task 7A Helicopter Support for Platform Installation Air Transportation On-Shore Short Term

Task 7B Tugboat Support for Platform Installation Marine Transportation Off-Shore Short Term

Task 7C Supply/Anchor Boat Support for Platform Installation Marine Transportation Off-Shore Short Term

Task 7D Longshoring for Platform Installation Marine Transportation On-Shore Short Term

Task 7E Other Onshore Support for Platform Installation Marine Transportation On-Shore Short Term

Island On-Shore Short Term

UNIT 8 Number of Production Shore Task 8 All Shore Base Construction Activities Air Transportation On-Shore Short Term

Bases Constructed Marine Transportation On-Shore Short Term

Island On-Shore Short Term

UNIT 9 Number of Production or Task 9 All Work of the Drilling Crews Marine Transportation Off-Shore Short Term

Service Wells Drilled Island Off-Shore Short Term

Exhibit 3-5: Assignment of Task Manpower to Local Community

UNIT 10 Offshore Oil Pipe Layed Task 10 All Work of the Laying Barge Crews Marine Transportation Off-Shore Short Term

(100's of Miles) Island Off-Shore Short Term

Task 10A Helicopter Support for Pipe Laying Air Transportation On-Shore Short Term

Task 10B Tugboat Support for Pipe Laying Marine Transportation Off-Shore Short Term

Task 10C Supply/Anchor Boats for Pipe Laying Marine Transportation Off-Shore Short Term

Task 10D Longshoring Support for Pipe Laying Marine Transportation On-Shore Short Term

Task 10E Other Onshore Support for Pipe Laying Marine Transportation On-Shore Short Term

Island On-Shore Short Term

UNIT 11 Onshore Oil Pipe Layed (100's of Miles) Task 11 All Pipeline Laying and Related Activities Island On-Shore Short Term

UNIT 12 Number of Marine Oil Terminals Constructed Task 12 All Related Activities Island On-Shore Short Term

UNIT 13 Number of Onshore Oil Pump Stations Constructed Task 13 All Related Activities Island On-Shore Short Term

UNIT 14 Number of Production Islands Constructed Task 14 All Related Activities

UNIT 15 Number of Production Task 15 All Work of Platform Operations Crews Marine Transportation Off-Shore Long Term

Platforms Operating Marine Transportation Off-Shore Long Term

Island Off-Shore Long Term

Island Off-Shore Long Term

Task 15A Helicopter Support for Platform Operations Air Transportation On-Shore Long Term

Task 15B Supply/Anchor Boats for Platform Operations Marine Transportation Off-Shore Long Term

Task 15C Longshoring for Platform Operations Marine Transportation On-Shore Long Term

Task 15D Other Onshore Work for Platform Operations Marine Transportation On-Shore Long Term

Island On-Shore Long Term

UNIT 16 Number of Major Platform Task 16 All Work of Platform Maintenance Crews Marine Transportation Off-Shore Long Term

Maintenances Performed Island Off-Shore Long Term

UNIT 17 Number of Production Island Maintenances Task 17 All Work of Island Maintenance Crews

UNIT 18 Number of Production or Task 18 All Work of Workover Crews Marine Transportation Off-Shore Long Term

Service Well Workovers Island Off-Shore Long Term

UNIT 19 Number of Production Task 19 All Base Operations Air Transportation On-Shore Long Term

Shore Bases Operating (Except tasks related to Units 6, 7, 10, and 15) Marine Transportation On-Shore Long Term

Island On-Shore Long Term

UNIT 20 Number of Marine Oil Task 20 All Terminal Operations Activities Marine Transportation On-Shore Long Term

Terminals Operated Island On-Shore Long Term

• Step IV.B.: Calculate Total Man Years by Industry

In this step the matrix of total man years by location, employment term, and skill level calculated 

in Step III.A are aggregated into forecasts of petroleum related employment by industry. The
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DOI-MMS 41 Arctic IMPAK

industries include mining, transportation (with sub-categories for air and marine transportation),

and construction. Employment at headquarters, forecast in step I.D, is added to the mining

industry forecasts.

Level V: Man Years by Alaska Residents

In this level, estimates are made of the man years supplied by Alaska residents by their place of

residence within Alaska.

• Step V.A.: Forecast Total Petroleum Related Man Years Performed by Alaska Residents by

Place of Residence

The final step in the manpower model distributes forecast man years held by Alaska residents to 

residential areas. Total man years held by nonresidents, forecast in step III.C, are subtracted

from total industry man years calculated in step IV.B. to produce estimates of the total man years 

held by Alaska residents. These results are then distributed to residential areas using the

percentages developed in step I.E.

Analysis of the Manpower Model

The Manpower model has the advantage of having been estimated specifically for the oil and gas 

industry in Alaska whereas other available models contain data at more aggregate activities. 

These models have production functions or input coefficients or labor factors that are based on

national level statistics and technologies. Most available input-output based models were

constructed based on data for the oil and gas extraction industry at the national level and

therefore do not accurately portray the specifics for arctic operations.

The model also has the advantage of treating the industry as a set of events that can be combined 

in different proportions to produce a final output. If the model calculated manpower solely on

total dollars spent or barrels produced, it could not accurately measure the differences in impact

from alternative production options or circumstances.

On the other hand, since the model only is concerned with labor inputs it fails to recognize that

differences in production methods may create differences in impacts. Two different production

scenarios may utilize the same amount of labor but result in much different impacts on the local 

economy. For example, one production scenario may use high technology such as caisson

islands supported by helicopters while another might rely on ice roads and gravel islands. The

former would use more highly skilled imported labor and imported equipment while the latter

would use more local labor and materials.

One set of problems related to Manpower is the lack of documentation. There are no

descriptions of where and how the data were obtained or processed, what assumptions were

made or what the problems and solutions were. As a result, assessing the validity of the model is 

hampered.
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DOI-MMS 42 Arctic IMPAK

A current shortcoming of the Manpower Model is that the units/activities appear less than

comprehensive. An example of the lack of comprehensive coverage is that the model does not

appear to address the costs of spill protection or the abandonment/cleanup that would be faced

when production is terminated. At present, calculation of the effects of a spill on the economy

are estimated outside the model by taking the size of a hypothetical spill as a proportion of the

Exxon Valdez oil spill. No estimates of the permanent spill contingency workforce are included.

To respond to this shortcoming, it is clear that the beginning and end of the activity stream that is 

modeled needs to be defined better. Moreover, these points probably should differ depending on 

whether the impact assessment is conducted at the state level or whether it is conducted at the

local level. For example, for a North Slope assessment the stream may end when oil enters the

Trans-Alaska Pipeline System (TAPS); for a state level assessment, however, there are activities 

in Valdez associated with transferring the oil from TAPS to vessels that need to be incorporated 

in the model.

In addition, the activities and data need to be updated to reflect production processes currently

used on the North Slope. This is perhaps less a critique of the model than an observation that

models of this type have a limited period of usefulness and must be updated on a regular basis.

3.3 THE RURAL ALASKA MODEL

The Rural Alaska Model (RAM) is currently the second step model used by MMS for assessing

secondary economic impacts on Alaska's North Slope Borough. Under the current modeling

procedure, total direct employment impacts in the oil industry are estimated in the first step

model (the Manpower Model) and then entered into RAM which estimates secondary and

ancillary impacts.

The RAM model was developed by the University of Alaska and consists of a set of worksheets

in a spreadsheet workbook. The RAM is actually a collection of ten models, one for each of ten 

local regions, one of which is the North Slope Borough.

Structure of the RAM

The North Slope Borough RAM consists of three linked modules: a demographic module, a

government fiscal module, and an economic module. Many of the variables in these modules,

but not all of them, are affected by the total direct employment impacts on the oil industry. For 

example, the fiscal module calculates the resulting changes in property taxes and in government

expenditures and revenues. The demographic module estimates population and migration

changes due to total employment changes in the oil industry. Finally, economic variables

affected by direct employment impacts on the oil industry include labor demand, labor supply,

total employment, and unemployment.
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DOI-MMS 43 Arctic IMPAK

Many of the variables are broken down by residential (residential vs. non-residential) and/or

Native (Native vs. non-Native) aspects. Further detail is often provided by aggregate sector: e.g., 

government, construction, endogenous support, et cetera. Each sector estimate relies on a single 

parameter (multiplier) computed outside of both models. There is also a dynamic component in

RAM. In other words, the value of a given variable at time "t" may be a function not only of

other variables at time "t" but also of variables at time "t - 1". 

To estimate secondary impacts, RAM relies on an economic base modeling approach. In other

words, total employment in the economy is related to employment in the economic base, which

is typically defined as the industrial sector. This relationship is defined in terms of an

"endogenous support" parameter, which is simply the ratio between total employment and base

employment. In the original North Slope version of RAM, constructed in the 1980's, these

parameters were estimated by Gunnar Knapp at the University of Alaska Anchorage.

A schematic of RAM is provided in Exhibit 3-6. Note that the schematic only details the

relationships between variables which are directly or indirectly stimulated by total oil industry

employment. The equations that comprise the variables in the schematic are shown in Exhibit 3-

7.
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DOI-MMS 45 Arctic IMPAK

Exhibit 3-7 RAM Equations

Line Number Variable Equation

316 Total Population Non Resident Population + Resident Population

320 Non-Resident Population Non-Resident Employment * Ratio of Non-Resident Population to NonResident Employment

365 Per Capita Operations Revenue Limit Total Population * Per Capita Operating Revenues

372 Property Taxes for Operations The minimum of the Per Capita Operations Revenue Limit, the Maximum 

Tax Rate for Operations, and the Maximum Total Tax Rate.

373, 385 Total Operating Revenues Non-property Tax Operating Revenues, Interest Revenues, and Property 

Tax Operating Revenues

375 Total Property Taxes Property Taxes for Operations + Property Taxes for Debt Payments

376 Total Revenues Total Operating Revenues + Property Taxes for Debt Payments

400 Total Employment in Government Operations Operations Expenditures * Employment Parameter for Government 

Operations

403 Total Employment in Endogenous Support Employment Parameter for Endogenous Support * Total Resident 

Employment

404 Basic Oil Industry Employment Data Input

408 Total Employment The Sum of Employment in Government Operations, Government 

Construction, Private Construction, Endogenous Support, Basic Oil 

Industry, Other Basic Activities, and Non-Local Government

409 Total Non-Oil Employment Total Employment - Basic Oil Industry Employment

424 Labor Demand for Natives in Government Operations Total Employment in Government Operations * Maximum Share of Natives 

in Government Operations

427 Labor Demand for Natives in Endogenous Support Total Employment in Endogenous Support * Maximum Employment Share 

of Native in Endogenous Support

428 Labor Demand for Natives in Basic Oil Industry Basic Oil Industry Employment * Labor Force Participation Rate for Natives

431 Total Non-Oil Labor Demand for Natives Labor Demand for Natives in Government Operations, Government 

Construction, Private Construction, Endogenous Support, Other Basic 

Activities, and Non-Local Government

439 Native Non-Oil Employment If Total Non-Oil Labor Demand for Natives > (Native Labor Supply - 

Minimum Native Oil Employment) then Native Labor Supply - Minimum 

Native Oil Employment; else Total Non-Oil Labor Demand for Natives

440 Native Labor Supply for Oil Industry If Non-Oil Labor Demand for Natives > Native Labor Supply-Min Native Oil 

Employment, then Min Native Oil Employment; else, (Native Labor SupplyMin Native Oil Employment-Non-Oil Native Labor Demand)*Native Labor 

Supply Parameter +Min Native Oil Employment

442 Native Oil Employment If Labor Demand for Natives in Basic Oil Industry Employment > Labor 

Supply for Natives in Basic Oil Industry, then Labor Supply for Natives in 

Basic Oil Industry; else, Labor Demand for Natives in Basic Oil Industry

443 Total Native Employment Native Oil Employment + Native Non-oil Employment

444 Native Unemployment Before Migration If Total Native Employment > Native Labor Supply, the 0; else Native Labor 

Supply - Native Labor Employment

445 Native Unemployment Rate Before Migration Native Unemployment / Native Labor Supply

448 Employment of Natives in Government Operations Labor Demand for Natives in Government Operations / Total Non-Oil Labor 

Demand for Natives * Native Non-Oil Employment

451 Employment of Natives in Endogenous Support Labor Demand for Natives in Endogenous Support / Total Non-Oil Labor 

Demand for Natives * Native Non-Oil Employment

457 Employment of Non-Natives in Government Operations Total Employment in Government Operations - Native Employment in 

Government Operations

458 Employment of Non-Natives in Endogenous Support Total Employment in Endogenous Support - Native Employment in 

Endogenous Support

463 Employment of Non-Residents in Basic Oil Industry Basic Oil Industry Employment - Native Oil Industry Employment

465, 322 Total Employment of Non-Residents Non-Resident Employment in Non-Local Government + Non-Resident 

Employment in Government Funded Construction + Non-Resident 

Employment in Basic Oil Industry

467 Total Resident Employment Total Native Employment + Total Non-Native Employment

475 Out-Migration of Native Workers If Native Unemployment Rate (UR) Before Migration (NURBM) > Max UR 

(MUR), then (NURBM-MUR) * Native Labor Supply (NLS); else, if NURBM 

> End of Period UR for Previous Year (EPURPY),then Share of Newly 

Unemployed Who Leave * (NURBM-EPURPY)*NLS; else 0

476, 28 Out-Migration Share of Native Adults Outmigration of Native Workers / Native Adult Population

477, 478 End of Period Native Unemployment Rate Native Unemployment Rate Before Migration - (Native Outmigration / 

Native Labor Supply)
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DOI-MMS 46 Arctic IMPAK

Analysis of the RAM

Compared to more complex regional input-output model such as IMPLAN or REMI, RAM is

somewhat simple. It relies on a total of six parameters per year to estimate the secondary

impacts. However, given the small size of the North Slope economy, as well as the fact that a

large component of the economy is subsistence/traditional, this may not be a serious

disadvantage.

Applying a large complicated model to a small economy such as the North Slope Borough can

result in less accurate forecasts than those predicted by more simple models. Large models such 

as IMPLAN rely upon thousands of parameters, many of which are based upon state or national

level data. Error is introduced, therefore, whenever such parameters do not correspond with the

realities of the local economy. It should be remembered that RAM was updated in 1995 with the 

best data available for the North Slope.

One disadvantage of RAM is that it does not isolate specific economic effects which may be

useful to MMS analysts. For example, it does not differentiate between indirect and induced

impacts; nor does it specify which impacts are attributable to residents and non-residents. A

model such as IMPLAN, on the other hand, can be used to model such questions. Due to the size 

and nature of the 

North Slope economy, the secondary impacts are going be comprised mostly of induced effects: 

IMPLAN could be used to estimate the induced impacts attributable to residential spending, the

induced impacts attributable to non-residential spending, and induced impacts attributable to

other sources of income such as the Alaska Permanent Fund.

Moreover, while the indirect impacts may be less significant, some impacts will accrue to

margins such as the transportation and retail trade sectors. IMPLAN can be used to estimate

those impacts even thought the primary manufacturing activity itself takes place outside of the

region. And again, it may be possible to isolate the indirect impacts due to an increase either in

resident jobs or in non-resident jobs. Looking at both indirect and induced impacts, it may be

possible to estimate the total secondary impact of non-residential spending and jobs on resident

income and jobs.

The other disadvantage of RAM is that it does not come with a state or national level geographic 

model which can be used to assess impacts on the entire state of Alaska or on the U.S. as a

whole. While another model could be used for this purpose, it would not be fully consistent with 

RAM and would be difficult to tell whether differences in magnitude were due to differences in

absorption or due to differences in model assumptions.

This lack of a state or national model is important because MMS has a need to evaluate impacts

across regions. Section 18 of the OCS Lands Act requires that Interior prepare a 5-year schedule 

of lease sales that considers “an equitable sharing of developmental benefits and environmental
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DOI-MMS 47 Arctic IMPAK

risks among the various regions.” MMS has made the decision to use IMPLAN for equitable

sharing analysis. RAM is therefore at a disadvantage both because it does not provide the data

required for the equitable sharing analysis and because it does not provide data directly

comparable with IMPLAN.

3.4 THE IMPLAN MODEL

The calculation of indirect and induced impacts requires an economic model that can appraise

impacts through multiple tiers of expenditures. One such model is IMPLAN, a regional

economic modeling system developed by the U.S. Department of Agriculture’s Forest Service in 

cooperation with the Federal Emergency Management Agency and the U.S. Department of

Interior’s Bureau of Land Management. The model was then maintained by the University of

Minnesota before being spun off to a private group in Minnesota. The IMPLAN model was

recently selected by MMS to estimate the impact of E&D activities for all geographic areas other 

than Alaska.

Structure of the IMPLAN Model

IMPLAN uses input-output analysis (a method of examining relationships between producers

and consumers in an economy) to analyze the effects of an economic stimulus on a specified

economic region

IMPLAN provides data at three basic geographic levels: national, state, and county (boroughs in 

Alaska). These geographic units, or customized regions based on zip codes, can be combined to 

construct any regional grouping the user desires. The ease with which alternative regional

aggregations can be constructed while preserving critical trade flow information, is a principal

advantage of IMPLAN.

There are two major components in the IMPLAN model: a descriptive model and a predictive

model. The descriptive model is represented by accounting tables that describe the trade flows

between producers and consumers in the region. The trade flow data provides information that

detail not only describes intra-regional flows, but also flows between the study area and the "rest 

of the world". The descriptive model also incorporates Social Accounting Matrices (SAMs),

which show money flows between institutions: e.g., taxes paid by consumers to governments and 

transfer payments from governments to businesses and households

The predictive model consists of a set of multipliers that can be used to forecast changes in the

economy. Multipliers are the means by which the initial change is translated into direct, indirect, 

and induced impacts. Thus, IMPLAN can be used to predict the regional economic

repercussions due to changes in supply or demand or due to changes in model parameters (e.g.,

income tax rate).
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Analysis of the IMPLAN Model

The IMPLAN multipliers are based upon the descriptive model and are computed only after the

regional economic accounts have been completely defined. This is an important advantage of

IMPLAN. In the descriptive model, all of the model parameters can be changed to reflect a

particular scenario or situation. Consequently, the resulting multipliers embody such changes. 

Examples of parameters that can be changed include regional purchase coefficients, margin rates, 

and production coefficients. These concepts are defined in the following paragraph.

Industry production coefficients are calculated as the quantity of a given production input (e.g., 

steel) divided by industry output. For each commodity, regional purchase coefficients specify

the percentage of demand accounted for by local production. Margin rates are used to divide the 

total cost of a commodity (from the buyer's point of view) into various cost categories: e.g., the

production margin is the cost of the commodity at the factory gate where it was produced;

transportation margins reflect transportation costs involved in delivering the product from the

factory to the buyer; and wholesale and retail margins are associated charges paid for those

services.

Some regional models, such as RIMS II, only provide the multipliers for evaluating economic

impacts and do not provide the descriptive accounts that can be used to developed custom 

multipliers. Since they are not able to incorporate specific conditions in a local economy, the

impacts predicted by these models are usually less accurate than impacts predicted by a model

such as IMPLAN.

IMPLAN conducts its analysis for 528 industrial sectors, primarily a mix of 4-digit and 3-digit 

SIC sector detail. This highly detailed sectoring plan is critical in input-output modeling, where 

the production function determines the indirect impacts associated with increased output in an

industry. In a highly aggregated sectoring plan (for example, 2-digit SIC level) the production

function coefficients and impact multipliers are averaged over all the different firms that

comprise each 2-digit SIC group. Therefore, a specific facility of interest may have a production 

process that differs substantially from that represented at the 2-digit SIC level. Modeling

impacts at the 4-digit level reduces the inaccuracies associated with industry aggregations.

Impacts can be evaluated for an individual event or for groups of events. The ability to group

events is an important feature that can be used to deal with aggregation problems. For example, 

IMPLAN's wholesale trade sector consists of numerous industries with very different production 

processes. Note that the wholesale trade production function represents an average of all of these 

different industry production processes. If the focus of analysis is on only one of these

wholesale trade industries, stimulating the entire wholesale trade sector may lead to large

inaccuracies if that industry's production process is very different from the average wholesale

trade sector production process.

A more accurate approach might use a procedure such as the following: (1) determine the

production function of the individual industry; (2) determine the change in the industry's output
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DOI-MMS 49 Arctic IMPAK

and the associated input changes for each sector; (3) for each input, stimulate that sector's output 

with the change calculated in (2). Stimulating a sector's output is an individual event in

IMPLAN. The ability to combine the stimulation of all of the input sectors (i.e., individual

events) into a group makes it possible to model industry output change more accurately.

A similar approach could be used to stimulate IMPLAN using an OCS E&D scenario. The

production function for OCS oil and gas development would need to be determined and

multiplied by the levels of output specified in the particular E&D scenario. The resulting inputs

in each year could become an event that is used to stimulate IMPLAN.

3.5 OTHER REGIONAL AND LOCAL ECONOMIC MODELS

In addition to the RAM and IMPLAN models, there are several other economic models that

could be used as the second step model to calculate the indirect and induced impacts of OCS oil

and gas activities. These include the Regional Economic Models, Inc. (REMI), the Regional

Industrial Multiplier System (RIMS), and The Man-in-the-Arctic Program (MAP) model. These 

models are described in more detail in the following paragraphs.

REMI

The REMI (Regional Economic Models, Inc.) model is a dynamic regional input-output model

created and sold by the consulting firm of the same name. It has been used and continually

refined since 1980 to reveal the economic and demographic impact that public policy initiatives 

or external events may have on a local or regional economy and population. REMI is available

in 14-sector, 53-sector and 172-sector versions, all of which are available in Windows format. 

The REMI model is calibrated to many sub-national areas for forecasting and policy analysis.

The structure of the model incorporates inter-industry transactions and endogenous final demand 

feedbacks. In addition, the model includes substitution among factors of production in response 

to changes in relative factor costs, migration in response to changes in expected income, wage

responses to changes in labor market conditions, and changes in the share of local and export

markets in response to changes in regional profitability and production costs. The model

combines several different kinds of analytical tools including economic-base, input-output, and

econometric models and has the ability to account for business cycles.

REMI’s structure can be summarized as exogenous demands driving an iterative solution of

output and endogenous final demands. REMI estimates relative regional prices - wages,

production, costs, and profitability - which contribute to the region’s competitiveness. 

Competitiveness is reflected in changes in the regional purchase coefficients and export market

share coefficients. This simulation agenda is somewhat ambitious and the REMI models are

consequently very complicated. The REMI model is available for purchase, rental or individual

studies and at different levels of industry detail.
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While the REMI model also has an excellent reputation, MMS decided to use a static I-O model, 

because MMS wanted to be able to change the way it grouped onshore geographic units for

analysis. Changing “regions” requires that the model be rebuilt, something that is quite easy for

the user to do with IMPLAN but very time consuming or expensive with a dynamic model such 

as the REMI model. In addition, the IMPLAN model is already being used by several MMS

contractors, is easier to understand, and is less expensive than the REMI model.

RIMS II

In the 1970's, the U.S. Department of Commerce, Bureau of Economic Analysis developed a

method for estimating regional I-O multipliers known as RIMS (Regional Industrial Multiplier

System). In the 1980's, BEA completed an enhancement of RIMS known as RIMS II. RIMS II

is based on an accounting framework called an I-O table which shows for each industry the

industrial distribution of inputs purchased and outputs sold.

A typical I-O table in RIMS II is derived mainly from two data sources: BEA’s 1992 national IO table, which shows the input and output structure of nearly 500 U.S. industries, and BEA’s

1995 regional economic accounts, which are used to adjust the national I-O table to show a

region’s industrial structure and trading patterns. RIMS II multipliers can be estimated for any

region composed of one or more counties and for any industry, or group of industries, in the

national I-O table. Users must provide geographically and industrially detailed information on

the initial changes in output, earnings, or employment that are associated with the project or

program under study. The multipliers can then be used to estimate the total impact of the project 

or program on regional output, earnings, and employment.

The RIMS II method for estimating regional I-O multipliers is basically a three step process. In 

the first step the producer portion of the national I-O table is made region-specific by using fourdigit SIC location quotients (LQs). RIMS II uses LQs based on two types of data: BEA’s

personal income data (by place of residence) for LQs in the service industries; and BEA’s wageand-salary data (by place of work) for the LQs in the nonservice industries. The household row

and the household column from the national I-O table are made region-specific in the second

step. In the last step, the Leontief inversion approach is used to estimate multipliers. This

inversion approach produces output, earnings, and employment multipliers, which can be used to 

trace the impacts of changes in final demand on directly and indirectly affected industries.

The greatest disadvantage of the RIMS II model is the lack of flexibility. For example, RIMS

does not allow for the creation of custom multipliers based on specifics of the Alaska economy. 

This is an essential part of improving the accuracy of the impact estimates and creating these

custom multipliers can easily be done with IMPLAN. Moreover, since MMS has already

chosen to use IMPLAN for other regions, this model would not provide comparable results for

the equitable sharing analysis.
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MAP

The Man-in-the-Arctic Program (MAP) model was developed by the University of AlaskaAnchorage for the Minerals Management Service (MMS) in the 1980's. Using direct OCS

employment projections from the Manpower Model and Exploration and Development scenarios 

from MMS, the MAP can project indirect and induced employment, State government revenues, 

and the sum of local government revenues within Alaska.

According to staff at the University of Alaska Anchorage Institute of Social and Economic

Research, the MAP model is updated when the Institute has received contracts for which using

the MAP was appropriate. This has generally occurred every year or so.

One drawback of the MAP model is that the Institute would require funds to update it and

charges a fee for each run. In addition, as MMS has already chosen to use IMPLAN for other

regions, this model, like RIMS and REMI, would not provide comparable results for the

equitable sharing analysis.

3.6 CRITIQUE OF CURRENT MODELING PROCEDURE

The current procedure for modeling the economic impact of oil and gas exploration and

development on the North Slope has both strengths and weaknesses. Many of these are inherent 

to the two models, Manpower and RAM, used in the analysis. Others are an outgrowth of the

combination of the two models.

As discussed earlier, the Manpower model has the advantages of having been estimated

specifically for the oil and gas industry in Alaska and of treating the industry as a set of events

that can be combined in different proportions to produce a final output. On the other hand, since 

the model only is concerned with labor inputs it fails to recognize that differences in production

methods may create differences in impacts. Moreover, it is poorly documented, current

activities appear less than comprehensive and there is a need to update the model to reflect

production processes currently used on the North Slope. Finally, the structure of the current

Manpower model is inflexible in that many parameters are held fixed for the forecast horizon

and are imbedded in equations such that they are not easily adjusted.

The RAM model also has the advantage of being specifically tailored to the local area as well as 

benefiting from a recent update. While it is somewhat simple this may be an advantage

compared to the errors that might result from applying a large complex model based on state and 

national data to a small unique economy. On the other hand, RAM does not differentiate 

between indirect and induced impacts, nor does it specify which impacts are attributable to

residents and non-residents. It also may be too simplistic in the assumption that the ratio of

indirect to direct impacts is independent of the level of activity or the technology used. A final

disadvantage of RAM is that it does not come with a state or national level geographic model

which can be used to assess impacts at the state or national level.
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The combination of the two models also introduces some additional disadvantages. One is that

all of the Manpower output is reduced to a single number, total oil industry employment

excluding headquarters employment, for entry into the model. All of the rich detail on skill

levels, industry, Native/non-Native employees, and onshore/offshore location is lost. A second

concern is the extent to which the definition of what is part of the oil industry may not be

consistent between the two models. The Manpower model contains a variety of activities that

together comprise the model’s definition of the oil industry. At the same time, the RAM model

has a multiplier based on economic base modeling approach where total employment in the

economy is related to employment in the economic base. However, if the economic base is

defined in a vastly different manner in this model than in the Manpower model this may result in 

an improper accounting of indirect activities. These indirect activities are the support functions,

often not provided by the oil companies, but supporting their operations.

3.7 ALTERNATIVE MODELING PROCEDURES

The current modeling, especially with an updated Manpower model, appears capable of

providing reliable estimates of economic impacts for the local area. However, additional

alternatives exist that may also provide credible local estimates. At the same time these

alternatives may also offer several other desirable features including:

• Estimates of impacts for the entire state

• Estimates of impacts for the other states or areas including national estimates

• Estimates that are consistent with MMS economic impact estimates for E&D activities in

other regions

• Separate estimates of indirect and induced impacts

• Estimates of distributional impacts.

The remainder of this chapter examines alternative methods that might be employed to model

economic impacts. Alternative methods for modeling economic impacts that will be examined

include:

• New Manpower model and RAM

• New Manpower model and MAP

• The full vector approach (Artic IMPAK) with alternative “national model”

• The full vector approach (Artic IMPAK) with IMPLAN

The full vector approach refers generally to the project team’s proposal to develop complete I-O 

vectors for each sub-activity, rather than just labor inputs as originally envisioned by MMS. A

basic setup of the data to be developed for this approach is provided in Exhibit 3-8. Note that his 

exhibit merely provides a simplified example of what the output of this procedure would look

like. The sectors provided are merely examples as is the format of the data. Actual tables are

developed and provided in later chapters of this report.
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The remainder of this section will describe each of the alternative approaches, discuss their

potential strengths and weaknesses, and estimate the difficulties in developing the data and

models to utilize each method. Alternative approaches will then be ranked and the top

alternatives to the current methodology will be identified.

EXHIBIT 3-8: BASIC SETUP OF TABLE FOR NEW MANPOWER MODEL, ARCTIC IMPAK

SIC CODES

IMPLAN

Sectors Expenditures

% Spent in

Study Area

% Spent in

Alaska

% Spent in

Rest of U.S.

1. 131 (Natural gas & crude petroleum 38 $$ X% X% X%

2. 132 (Natural gas liquids) 37 $$ X% X% X%

3. 1629 (New gas utilities & pipeline

 construction)

50 $$ X% X% X%

4. 1629 (misc. nat. res. Fac. construction 53 $$ X% X% X%

5. 1381, 1382, 1389 (New well drilling,

 O&G ex., other O&G svcs.)

57 $$ X% X% X%

6. 2899 (Chemicals, nec) 209 $$ X% X% X%

7. 291 (Petroleum fuel) 210 $$ X% X% X%

8. 324 (Hydraulic cement) 232 $$ X% X% X%

9. 3317 (Steel pipe) 258 $$ X% X% X%

10. 3443 (Fabricated plate work) 284 $$ X% X% X%

11. 3462 (Iron & steel forgings) 290 $$ X% X% X%

12. 3511 (Turbines) 307 $$ X% X% X%

13. 3531 (Const. mach. & equip.) 311 $$ X% X% X%

14. 3533 (O&G field machinery) 313 $$ X% X% X%

15. 3559 (Spec. ind. Mach. Nec) 331 $$ X% X% X%

16. 3561, 3563 (Pumps & compress.) 332 $$ X% X% X%

17. 3613 (Switchgear) 356 $$ X% X% X%

18. 3731 (Shipbuilding) 392 $$ X% X% X%

19. 3823 (Instrumentation) 403 $$ X% X% X%

20. 44 (Water transport.) 438 $$ X% X% X%

22. 45 (Air transport.) 437 $$ X% X% X%

22. 58 (Eating/drinking places) 454 $$ X% X% X%

23. 7359 (Misc. equip. rent/lease) 473 $$ X% X% X%

24. 8731, 8732, 8734 (Test/resrch. Svcs.) 509 $$ X% X% X%

25. 871 (Envir./engineering svcs.) 508 $$ X% X% X%

26. 872, 879 (Acctg./misc. bus. Svcs.) 507 $$ X% X% X%

EMPLOYEE COMPENSATION NA $$ X% X% X%

 Wage Rate

 Total Man-Hour Per Year

 Total Man-Months Per Task Per Unit

 Duration of Task (Months)

 Total Task Workforce Per Unit

 Task Crew Size

 Shift Factor

 Rotation Factor

New Manpower Model and RAM

In addition to developing expenditure vectors the project team compiled employment and payroll 

figures for each unit and activity. This allows for a full accounting of the first round direct

impacts in terms of both expenditures and employment. As was past practice, it is still possible
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DOI-MMS 54 Arctic IMPAK

to use the sum of the direct employment impacts (residential + non-residential, excluding

impacts at headquarters) to stimulate RAM.

Since the updated manpower model is more comprehensive in terms of the activities

incorporated, the direct impacts may be higher than previously estimated. Such an outcome

would also result in relatively higher estimates of the secondary impacts.

Given the use of RAM, the criticisms of RAM cited above would apply to this approach.

New Manpower Model and MAP

While it is conceivable that the manpower model could provide inputs that would allow the MAP 

model to estimate economic impacts this option was never seriously considered due to the cost of 

the MAP model and the fact that it would not provide comparable results for the equitable 

sharing analysis. The same criticisms hold true for using the MAP model together with the full

vector approach.

Full Vector Approach (Artic IMPAK) With Alternative “National Model”

The full vector approach could be applied with an alternative national model. However, as

described above, REMI and RIMS II, the two most widely used alternatives, have drawbacks in

terms of cost and flexibility, respectively. In addition, these models would not provide

comparable results for the equitable sharing analysis. For MMS to develop its own national

model would require too much staff time and expertise. Relying on lesser-known models would 

raise questions of future availability and other concerns.

Full Vector Approach (Artic IMPAK) with IMPLAN

The IMPLAN model provides the best alternative to the continued use of Manpower and RAM. 

Such a modeling scheme will provide detailed breakdowns on local impacts as well as state and

national data that will be comparable to the IMPLAN generated data for other areas under study 

by MMS. The main questions concern the accuracy of the local impact data that will be

generated by IMPLAN as compared to the more locally tailored RAM model. The belief is that

the detailed first step model employing the full vector approach (Artic IMPAK) will provide

such a complete version of local first round impacts that IMPLAN will be capable of accurately

generating the secondary impacts.

The following paragraphs discuss some of the technical considerations in the application of the

IMPLAN model.

For each activity, the updated Manpower Model will generate employment estimates, capital

assets used (e.g., number of helicopters), and a vector of input expenditures (including payroll). 

How those data are brought into IMPLAN will depend upon whether the activity is a

construction activity or an operations activity. 
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If the activity is an operations activity, the data will probably be entered in the following way. 

First, each intermediate input used in the operation will be mapped to an IMPLAN sector. 

Second, those sectors will be stimulated with output changes that depend upon the activity level. 

 Third, personal consumption expenditure (PCE) vectors in IMPLAN will be simultaneously

stimulated based upon worker earnings due to the activity. Here several considerations will

come into play. For instance, the earnings will have to be converted into disposable income

estimates using tax and savings rate information. Since there are nine PCE vectors in IMPLAN, 

each one associated with a different income group, it will also be possible to allocate the

earnings among these income groups or to select one of them. Another consideration is the

different expenditure patterns that may be exhibited by residents and non-residents: if this is the

case, it may be desirable to divide the earnings between to these two groups, and then customize 

their expenditure patterns.

If the activity is a construction activity, a few additional steps and/or considerations may be

required. For example, the construction activity may include the purchase and installation of

industrial machinery (i.e., equipment investment), which is not an intermediate input per se. 

These investments still should be mapped to IMPLAN sectors and the output of those sectors

stimulated according to the associated activity level. At this point, the analyst has a choice in

how to proceed. One avenue is to stimulate the correct construction sector with the difference

between the total construction cost and the equipment investment. This is the easiest approach to 

take and does not require multiple adjustments of the PCE vectors. However, using this approach 

it would not be possible to incorporate the different expenditure patterns between the residents

and non-residents. The other approach is to follow the approach outlined for operations. While

this approach will probably yield more accurate results, the analyst should avoid mapping any of 

the inputs into IMPLAN's construction sector. Doing so could result in double counting and

exaggerated impacts for some sectors. 

Another consideration will be how to treat the use of heavy equipment such as earth-moving 

equipment and bulldozers. Engineering cost will be developed for the use of such equipment. 

However, in some instances the equipment may be rented whereas in other instances it may be

owned by the company and a depreciation charge incurred. The first instance results in an

economic stimulus to the region; no stimulus is generated by the depreciation of the asset. Some 

rules of thumb or estimates may be needed to allocate these types of costs.

In using IMPLAN, the two other primary considerations will involve the use of margins and

regional purchase coefficients (RPCs). Retail margins should be used with the PCE vectors and

investment margins should usually be applied to the stimulation of the industrial sectors. The

IMPLAN margins will probably need to be modified to take into account the special

circumstances on the North Slope.

Regional purchase coefficients should also be used whenever possible: i.e., with the PCE vectors 

and the industrial sectors. Using RPCs with the PCE vectors makes sense since many retail

goods may be acquired outside of the North Slope (e.g., in Fairbanks). Note that even if an RPC 

is set to zero (meaning that the commodity is not produced locally), margin sectors in the region 
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such as transportation and wholesale trade can still be stimulated. Again, these adjustments to

the standard IMPLAN RPCs will probably be required to reflect the special circumstances on the 

North Slope.
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4. ENGINEERING DESCRIPTION OF THE ACTIVITIES

The purpose of this study was to develop economic data characterizing the inputs to the activities 

that comprise the exploration and development process in the Alaskan OCS. The beginning 

point in developing these data was the collection of detailed engineering descriptions of the

activities. These descriptions provide details on the economic inputs to the activities including

labor, materials, and equipment. For labor, these descriptions include information on the

numbers and pay rates for the various workers employed for each task. For materials, these

descriptions include information on the cost and quantity. For capital, information was often

gathered on the numbers and types of equipment purchased, along with separate estimates of the 

costs of shipping these pieces to the North slope and retrofitting them for the harsh arctic

environment

The following sections provide a summary of the information collected for the various activities 

including general descriptions of the engineering specifics of the activity, the sources of the data, 

and summaries of manpower requirements, capital needs and fuel and material inputs.

4.1 SEISMIC SURVEY

The manpower and input vector estimates were developed for one month of a geological

geophysical seismic survey on ice. Generally, ice in the Beaufort Sea will support survey

equipment from January 1st to May 1

st, limiting survey work to those months. Surveys can also 

be conducted on water, but this is generally not the case.

Surveys on ice are conducted using a caravan of vehicles designed to operate on the sea ice. 

These vehicles are often “tracked” vehicles (i.e., they use “tracks” rather than tires). The

majority of these “tracked” vehicles are manufactured by the Caterpillar Company and therefore 

the vehicles are often referred to as “cats” and the survey caravan as a “cat train”.

The average contract price per day for a seismic survey setup, including the cat train, is $120,000 

per day according to the contractors interviewed for this study. Assuming 30 days per month,

costs for a month would be $3.6 million. These are actual construction costs. It is assumed,

based on interviews with industry personnel conducted for this study that, by including costs of

oil company personnel permits, leases, royalties purchased services and all other resources, the

total dollar cost would be double to $240,000 per day or $7.2 million per month.

The analysis of the seismic survey activity is based on a series of interviews supplemented by the 

engineering and economic experience of project staff. Interviews that were conduct with the

following sources:

• A cat train manager for a firm providing cat train support for seismic surveys

• A truck operator for a seismic survey company
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• The owner of a firm providing cat train support for seismic surveys

• The owner of a seismic survey company

• An Anchorage equipment firm sales person who is assigned to the North Slope 

Territory

• The owner of a fuel/aviation firm

Overview of the Activity

The remainder of this section provides the engineering information that was collected from the

interviews and other sources. Included is general information on the activity and as well as more 

specific information on capital, labor and material inputs.

In general, to conduct a survey, a cat train company provides support for a seismic survey

company. In the case study, the cat train provider that was interviewed provides support on a

regular basis to one of the survey companies that were interviewed. In the paragraphs that

follow, a short summary of the seismic survey process is provided, followed by sections

describing the seismic survey camp, and the capital equipment, labor and fuel requirements.

The first step in conducting a survey is to run seismic lines. These lines may run 20 miles a day

requiring the entire cat train to move 20 miles per day. The lines consist of four ten-mile-long 

geophone lines run a quarter of a mile apart and connected to a CPU data collection unit. After 

the lines are set, two groups of five shaker trucks stop to shake the lines at vibration points every 

1/6th mile. The trucks "leap frog" between the center two jug lines. The lines establish basic

data over an entire lease area.

As the lines produce areas of interest, the next step is to set up a grid to profile the geological and 

geophysical characteristics of these areas. A grid consists of eight geophone lines, a quarter of a 

mile apart and ten miles long. The geophone lines ("jug lines") are connected to a CPU data

collection unit ("dog house"). This unit may be mounted on a “Foremost” truck or on a sleigh

pulled by a “Nodwell,” which is a track vehicle similar to a snow cat used at a ski area. Two

groups of five shaker trucks then "leap frog" across the jug lines at quarter mile intervals,

working up and down the grid until the ten miles of line have been covered. The shaker trucks

stop at every vibration point (VP). The shakes are initiated by a tone from a controller in the

doghouse, and all five trucks in a group shake at once. A shake consists of four, two second

shakes-one to set the plate and three to record data. There are eight VP's between each jug line. 

About 500 VP's per day are common and require 16 to 18 hours a day to accomplish.

Grid profiling requires the camp to move two to three miles every two days. If fuel is delivered 

by air, each camp move would require a runway to be plowed 1,500 feet long to accommodate

service from twin otters. If DC-6 fuel planes are used, a 5,000 feet airstrip is plowed.
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Camp Support

Surveys on ice require four D-7 cats, one Model 65 Cat Challenger, one 966 Cat loader and six

operators with the cat train company, and around 94 personnel and associated equipment with

the survey company. The D-7 winch cats are used on ice as their total weight is 51,000 pounds

each. The Challenger is a rubber tracked vehicle and is much faster than a steel tracked vehicle.

The cat train consists of six strings, each pulled by one of the D-7 cats, the 966 loader or the

Model 65 Challenger. A string is a series of sleighs pulled by one of the cats. The makeup of

each of the six strings is as follows:

String #1 - Office String of Three 60-foot Sleighs (or units)

The first sleigh in this string is a generator unit with a 500 gallon fuel tank. The rear half of the 

generator unit contains toilets, showers, and a washroom. The second sleigh is an office unit,

consisting of offices, a piece of equipment for snow melting, and staff sleeping quarters. An

incinerator is also towed behind this string.

String #2 - Kitchen String of Three 60- foot Sleighs

The first sleigh in this string is a generator unit with a 500 gallon fuel tank. The rear half of the 

generator unit is a mechanics shop. The second sleigh is the kitchen and dining area. The third is 

kitchen storage and quarters for the cooks.

String #3 - Quarters String of Three 60-foot Sleighs

The first sleigh is the generator unit, with fuel tank. The rear half of this first sleigh is the spare 

parts house. The second and third units are crew sleeping quarters.

String #4 - Cat Train Camp Support String of Three 60-foot Sleighs

The first sleigh in this string is a generator unit with a 3,000 gallon fuel tank. The rear third of

this generator unit contains toilets, showers, and washer and dryers. The second unit contains

sleeping quarters with offices. The third sleigh contains sleeping quarters with storage. A junk

sleigh may be towed behind this string, used for anything from spare tires, iron, and anything 

that has to be hauled back. This string is towed with a 966 Cat loader. A loader has many tasks 

on the train including loading snow into the snow melter.

String # 5 - Fuel String of Two 60-foot Sleighs

This string has two 60-foot sleighs, with two 3,000-gallon fuel tanks on each sleigh for a total of 

12,000 gallons.
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String #6 - Fuel String with Survival Unit

This string is the previous fuel string with the addition of an 8- foot survival unit, which is towed 

along to haul fuel from sources up to 70 miles away. A Cat Challenger Model 65 is used to pull 

this string, as the rubber tracks allow speeds three times that of a D-7, or approximately seven to 

ten MPH.

Equipment Purchase Cost and Location

The Cat Train equipment lasts about 10 years and then has to be replaced or rebuilt. In practice,

this equipment is usually replaced rather than rebuilt. The following information was gathered

on Cat Train equipment purchase location and cost.

• The D-7 winch Cats cost $360,000 and are purchased in Anchorage, at NC Machinery (NC). 

Arctic fitting costs average around $7,000 and shipping to the Slope costs $3,000.

• A Challenger 65 costs $190,000 at NC. It is then equipped with an angle blade for $20,000,

prepared for the arctic for $6,000, and shipped for $3,000.

• The Cat 966-bucket loader costs $260,000 at NC, with an additional $10,000 for arctic

preparation and $3,000 for shipping to the Slope.

The following seismic equipment lasts about seven years and has to be replaced. Rebuilding is

not practical due to technology changes with this type of equipment.

• Seismic recording lines, including the CPU or “doghouse,” cost about $2,000 per channel, or 

$6 million for this 100-man setup

• Ten Shaker trucks cost about $450,000 each, delivered to the Slope.

• Survey equipment costs around $300,000 including RTK and GPS.

• The Nine Nodwells that are used for jug trucks, personnel carriers and trouble-shooting were 

purchased for $2 million dollars total, delivered to the Slope.

• A 100-man camp, made by Arctic Camps, costs $2.2 million dollars, delivered to the Slope. 

The camp includes all of the modular sleigh mounted equipment, fuel tanks and quarters.

Fuel Supply and Cost

If the survey is being conducted in the area of the Prudhoe Bay infrastructure, rubber tired Delta 

fuel trucks may shuttle fuel that is refined at the Crude Oil Topping Unit (COTU) plant in

Prudhoe Bay. They haul 2,500 gallons per load. These trucks will normally haul to the end of

the ice roads, and then pump their load onto the Challenger fuel string. The Challenger may
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travel up to 70 miles to deliver fuel to the Cat Train. During the winter months on a cat train, all 

of the equipment runs 24 hours a day, as it is very difficult to warm equipment and to start in the 

Arctic.

The generators use an average of 150 gallons of fuel per day. The cats also use 150 gallons per

day. With all of the other equipment running 24 hours a day, the total fuel consumption for a

100-man cat train is 3,600 to 4,500 gallons per day. Most of the fuel used for surveys on ice is

refined at the COTU in Prudhoe Bay at a cost of $1.00 per gallon. The average cost for the Delta 

trucks to deliver the fuel is $0.50 per gallon. The Challenger rents for $77 per hour and $100

each for the fuel sleighs, for a daily cost of about $3,324 per day. The fuel cost per month for

Prudhoe refined fuel is $121,500 (not including transportation costs for the Delta trucks or the

Challenger fuel string).

If the survey is being conducted greater than 70 miles from a fuel storage source, a DC-6 fuel

plane delivers fuel from Fairbanks for $6,000 per load. However, according to sources

interviewed for this study, fuel planes have not been used in several years. The cat train cats

clear a 5,000 foot runway for the fuel plane.

Fairbanks fuel is around $0.65 per gallon at the North Pole Refinery, plus $0.11 per gallon

trucking to the airport and $6,475 per flight, for a delivered cost of $2.23 per gallon. The cost

per flight is based on $9.25 per statute flight mile from the Fairbanks Airport. The costs for

longer flights to the Chukchi and Hope Basin can be calculated based on this cost figure.

Personnel and Overhead Costs

Most of the 100 survey crew members work 4 weeks on and 2 weeks off. As a result, about a 30 

percent over hire is required. For the permanent employees (about half), there is a $7.00 per

hour benefit package. Workdays lasting 16 to 18 hours are common; so a lot of overtime, at time 

and a half, is paid. Meals are $37.00 per day per person. Overhead runs 38%.

The 100 personnel are paid as follows:

• Six catering staff at $14.00 per hour

• Four surveyors at $300 a day contract and three at $150 per day

• Six Cat train operators at $16.00 hour

• Crew includes 35 staff at $7.00 per hour, 8 staff at $8 per hour, 10 staff at $9 per hour and 6 

staff at $12 per hour

• The remaining 12 personnel at $4,583 per month salary.

4.2 NORTH SLOPE SUPPORT

The development of oil and gas resources on the North Slope is carried out in a remote

environment where all but a handful of local Native workers require short-term room and board. 
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 As a result, most of the workers involved in the various activities are housed in employer

provided hotel/camp type facilities. These facilities are most often run by contractors.

The manpower and input vector estimates for this activity were developed based on costs for an

actual 300-person hotel/camp. The owner of a facility of this type was among those interviewed 

for the study, and this source provided much of the manpower and cost data used in the

estimates.

The estimates assume that capital costs for the construction of the facility are sunk and are

therefore not included in the estimates. This provides the most accurate estimate of economic

impact, because it is unlikely that the activities to be modeled will require the construction of

new hotel/camp facilities. According to the interviews conducted for this study, it has been at

least 12 years since a new camp has been built. On the other hand, an old Native construction

camp was recently renovated for the Northstar project. As such, the costs of maintaining

facilities are included in the cost estimates, as these costs are ongoing.

In this study, these food and lodging activities are considered a secondary activity. As a result,

the level of this activity is determined by the levels of the primary activities that utilize

workforces that require these services. In the primary activities, employers are assumed to pay

$75 per day ($110 per day for supervisory personnel) for each worker that will be housed in a

hotel/camp. These payments are summed in the model and used to stimulate this vector. The

daily rate of $75 a day for food and lodging was developed from the interviews and verified

based on the experience of study personnel. The higher rate of $110 per day for supervisory

personnel covers the cost of office space and a private bath.

Total yearly revenue for the hotel/camp is estimated based on a capacity of 300 lodgers of whom 

two-thirds are assumed to be at the $75 per day rate and one-third are at the $110 rate. 

Furthermore, the hotel/camp is assumed to have a 365 day a year operating period and an

average occupancy of 80 percent. The resulting annual revenue estimate is $7,592,000.

The remainder of this section provides engineering information that was collected from

interviews and other sources. Included is general information on the activity and as well as more 

specific information on capital, labor and material inputs.

Overview of the Activity

According to the interviews, a resident staff of 20 is required to operate a 300-person hotel/camp. 

 However, total employment is thirty as ten more personnel would normally be on leave

(time-off). Ninety percent of the staff is unskilled at a cost of $300 per day. Ten percent is

skilled at a cost of $400 per day. Ninety percent of the staff is Alaska hire with the remaining

ten percent drawn from the other 49 states. Fifteen percent of the total staff is Native hire.

Major activities include the provision of food, laundry of linens and towels, provision of

electricity and heat, provision of water and sewer services and the maintenance of the property.
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The following paragraphs describe the major cost components required to operate a 300-person 

hotel/camp. The process is divided into six tasks. Each task description includes information on 

the types and quantities of labor employed, as well as the numbers and types of equipment used

and any materials required.

Task A: Food Service

On a weekly basis, four tractor-trailer trucks, from Fairbanks and Anchorage, service most of the 

camps/hotels on the North Slope. Two major vendors involved are Food Services of America

and Anchorage Cold Storage. The raw cost of food per person per day is $12. It is estimated by 

study engineering staff that one-third of this cost is for transportation costs. The food is then

prepared on-site and billed at the rate of $30 to $35 per person.

Task B: Commercial Laundry

Laundry is hauled back and forth to Fairbanks where it is processed once a week, along with 

housekeeping supplies, for a raw cost of $1 a day per person. Personal laundry is done in

laundry rooms located at the camp. It is estimated by study engineering staff that one-half of this 

cost is for transportation and that 75 percent of the remaining cost is for laundry and the balance 

for housekeeping supplies.

Task C: Power Generation and Co-generation

The hotel/camp used to develop this profile has its own generators that run on diesel fuel. Two

generators are maintained to provide backup in case one fails. In addition, the camp is tied into

the local power grid and provides or takes electricity when necessary. A few camps rely solely

on power from the local grid, but these camps are an exception to the rule. The raw costs for

operating the generators are 7.5 cents/KW/hr. It is estimated by study engineering staff that the 

generators would cost about $375 per hour to operate with $175 of this cost for capital, $150 for 

fuel, and $50 for miscellaneous material inputs including oil, antifreeze, “clean sweep” and other 

inputs including rags.

Task D: Water Treatment

The hotel/camp used to develop this profile has its own water treatment plant. Typically, lake or 

river water is hauled or pumped to the water treatment plant where it is filtered, chlorinated and 

treated with iodine and other chemicals. Eco-flush toilets and shower nozzles are used to

conserve water. A total of 20,000 to 25000 gallons per day (75-100 gallons per day per person) 

is used at approximately four cents per gallon. It is estimated by study engineering staff that the 

$900 daily cost is made up of $350 for hauling, $200 for capital, $150 for chemicals, $100 for

fuel (mostly electric) and $100 for filters.
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Task E: Sewage Treatment

The hotel/camp used to develop this profile has a grandfathered sewage plant with an

evaporative pond, and can process the 20,000 to 25,000 gallons per day of wastewater at a rate of 

2 cents per gallon. In some areas of the NSB, commercial processing and hauling of sewerage is 

required. Where this is the case, this cost can go as high as 19 cents per gallon. Most of the

existing camps, however, have their own sewage treatment. It is estimated by study engineering

staff that the $450 daily cost is made up of $150 for capital, $100 for chemicals, $100 for

incinerator equipment and $100 for fuel (mostly electric).

Task F: Building and Equipment Maintenance

Building and equipment maintenance is performed by two of the skilled staff. Office, shop, and

storage areas are required to keep records, repair appliances and equipment, and store spare

parts. A cost of $25,000 a month (not including labor) is average. Maintenance personnel must

be "jacks of all trades" and operate the generators, water and sewer plant, repair any camp

system, keep records, and maintain an inventory of spare parts. Maintenance items include light 

bulbs, windows, roofing materials, cabinets, doors, and appliances and parts.

4.3 GENERAL PASSENGER TRANSPORT

The manpower and input vector estimates were developed for one day of general passenger

transport. For this activity it is assumed that the operation will consist of a small transit type

operation with one forty passenger bus and three large 15 passenger vans.

This type of operation is of crucial importance on the North Slope. Work crews are constantly

rotating on and off duty whether from day to night shift or from two to four weeks on to two

weeks off. Since none of these workers live in the area, there are no personal passenger vehicles 

to transport them between the airport, the hotel/camp and the work site. Transport in the North

Slope area for OCS projects during the period ice roads can be used, is described in this section. 

In other periods of the year, helicopter transport is used, as discussed in another section of this

chapter.

No overall estimate of the cost of this operation is available. Total revenue for this operation

will, therefore, be estimated from the bottom up by summing estimates of labor, material, capital 

and purchased services. It is estimated from interviews with several contractors, as reported in

Section 4-1, that the average cost of this service per North Slope based production employee is

$15 per day.

The analysis of the general personnel transport support activity is based primarily on the

experience of project staff and their familiarity with this type of operation in the North Slope.
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The remainder of this section provides the engineering information that was collected from the

interviews and other sources. Included is general information on the activity and as well as more 

specific information on capital, labor and material inputs.

Capital Cost

In order to efficiently shuttle workforces primarily over ice roads between the airport, the

hotel/camp and the work site, a variety of buses, vans and pickups are used. For this

hypothetical operation, it is assumed there will be one bus and three vans. The bus has a

capacity of 40 people and is equipped for the arctic environment with extra heaters and

insulation at a cost of $75,000. The van has a capacity of 15 people and is equipped for the

arctic environment with extra heaters and insulation at a cost of $50,000. During the summer

transport to the islands is generally via helicopters with 12-passenger capacity.

Manpower and Cost

According to project staff, this hypothetical general passenger transport operation would be

staffed by four drivers, a two member maintenance crew, and a dispatcher/supervisor. 

According to the engineering project staff, personnel of this type would generally work two

weeks on and two weeks off. The employees would work a 12 to 14 hour day. There are no

Native employees in this operation. This is primarily because this function is integrated with a

security function and contracted out.

Fuel Use

It is estimated that the bus will consume 40 gallons of fuel per day and that the van will consume 

30 gallons of fuel per day.

4.4 ICE ROADS AND ICE ISLANDS

The manpower and input vector estimates were developed for a ten-mile ice road and a 500 foot 

diameter ice island. The estimates assume that the road is built to a minimum of five feet of

depth. This is the minimum depth to which ice roads are normally constructed and is an

adequate depth to support normal operations. However, if heavy equipment, such as drill rigs,

need to be transported the road will either have to be built to a thicker depth of 10 to 20 feet, or

grounded. In the IMPAK model, depths with a five foot minimum and twenty foot maximum are 

specified by the user.

The average contract price for minimum size five-foot thick floating ice road, according to the

contractors interviewed for this study, is about $50,000 to $55,000 per mile. The high end of the 

range was used here. By way of comparison, onshore tundra ice roads cost about $35,000 per

mile to construct. These are actual construction costs. It is assumed, based on interviews with

industry personnel conducted for this study that, by including costs of oil company personnel,
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permits, leases, royalties purchased services and all other resources, the total dollar cost would

be double to $110,000 per mile.

Costs for ice roads are estimated to increase more than proportionally to depth. For example a

10-foot deep road would cost four times more than a 5 foot deep road, a 20-foot deep road 

sixteen times as much. The costs of various size and depth roads can be estimated using these

relationships through the use of a simple algorithm.

The technology for construction of an ice island is nearly the same as for ice roads. The

construction costs for the ice island are developed by applying ratios of the relative surface areas 

or relative volumes to the task level estimates of labor, capital and materials. Relative surface

areas are used to adjust work tasks that involve surface areas while relative volumes are used for 

tasks that involve volumes. It is assumed the ice island is built to a depth of 20 feet.

The relative surface area of the island is 62 percent of one mile of ice road or 6.2 percent of a ten 

mile portion of ice road. The island has a 500 foot diameter or a 250 foot radius. The estimated 

surface area of the island is estimated by applying the formula for the area of a circle (Πr2). 

The resulting estimated surface area is 196,350 square feet. One mile (5,280 feet) of ice road at 

60 feet wide has a total area of 316,800 square feet.

The relative volume of the island is estimated to be almost 10 times greater than a mile of ice

road or approximately equal to ten miles of ice road. The ice road is to be built to five feet of 

depth, while the island is to be built to 20 feet of depth. As mentioned above, costs increase

more than proportionally to depth, such that an ice road of 20 feet depth is estimated to cost 16

times an ice road of 5 foot depth. Multiplying the factor of 16 for depth times the factor of 62

percent for relative surface area results in a factor of 9.9, which is a measure of relative volume

between an ice island and a mile of ice road.

Reliable data on the cost to construct an ice island were not provided in the interviews. The best 

guess available was that one would cost in the $500,000 range.

The analysis of ice road and island construction costs were based on a series of interviews

supplemented by the engineering and economic analysis experience of project staff. Interviews

were conducted with the owners of two construction firms that build ice roads.

Overview of the Activity

Ice road construction takes approximately a 50-man crew, a small grader, and snow blower

equipped with floats (capable of operation on 8" of ocean ice), four Rollagon pumpers, three

water trucks, two dump trucks, one ice mill mounted on a grader, one large grader, nine pickup

trucks and a survival shed. The first step is to travel out onto about 8" of ice with the small

grader and snow blower, removing the snow from the ice road path. This can normally start

around the last half of December. The snow removal process is ongoing through construction

and the end of ice road service life which is about the first of May.
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Next, the Rollagon pumpers are placed in service. They drill and pump in the same operation. 

They relay around each other, up and down the ice road, until the ice is thick enough for other

vehicles. The road is then staked with reflectors to identify the profiled road edges. Fresh water 

and milled ice chips are used to make ramps from shore to the ice and supplement the saltwater

drill-pump operation. The ice chips are hauled with dump trucks, and the fresh water is hauled

with water trucks equipped with fan spray nozzles. Any cracks that appear are repaired with

fresh water to keep the road from separating and drifting. The construction process continues

until the road is thick enough or grounded to handle the loads it will be employed for, including

drilling rigs.

The following paragraphs describe the process of building an ice road on a task-by-task basis. 

The process is divided into six tasks. Each task description includes information on the types

and quantities of labor that are employed, the numbers and types of equipment used and any

materials required. Differences between ice road and ice island construction, were applicable,

are noted.

Task A: Remove Snow with Small Grader and Snow Blower Equipped with Floats

Two operators and one supervisor, for each 12-hour shift, venture out on the ice when it is eight 

inches thick and remove the snow. This process takes about two days for the initial snow

removal on a 10-mile road. This equipment will be used as necessary until a large grader can be 

used for snow removal. For the ice island, with a much smaller surface area, this task is assumed 

to be completed in only one shift on one day.

The small grader used by the contractor interviewed is a Future 700 that weighs 5,000 pounds, is 

equipped with Rollagon bags for floats, and has an escape hatch in the roof. It was a previously

used machine that was reconditioned, equipped, and purchased from a Fairbanks dealer for

$50,000.

The snow blower is a Rolba R/200 purchased in Switzerland through an Anchorage-based dealer 

for $150,000, fully equipped and delivered to the North Slope.

Task B: Flood with Pumper-Augers on Small Rollagons

Two supervisors, two snow removal operators, and six pumper operators (each 12-hour shift)

drill, pump and move back and forth on the ice road with small Rollagons for 10 to 12 days until 

the ice is thick enough for larger equipment. For 10 miles of ice road this task is assumed to be 

completed in 11 days. For an ice island, with a much smaller surface area, this task is assumed

to be completed in only one day.

Small Rollagons were purchased in Louisiana, at a base price of $25,000 each, and equipped for 

ice road operation by Houston Rollagon on the North Slope for a final cost of $120,000 each,

including shipping to the North Slope.
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Task C: Flood with Water Trucks and Fresh Water

Once the road is thick enough for larger equipment, the road is flooded with fresh water. The

100-barrel trucks and fresh water are used on the floating portion of the road and the 300-barrel 

truck is used on anchored portion of the road for eight to ten days. For 10 miles of ice road this

task is assumed to be completed in nine days. For an ice island, with a slightly smaller volume

of material to be added, but a greater travel distance for moving the fresh water, this task is

assumed to be completed in ten days.

Two 100-barrel and one 300-barrel water trucks are used. The heavy-duty trucks were

purchased from an Anchorage based Kenworth dealer at $100,000 each. The tanks were

purchased from Petro Steel in Idaho for $50,000 and $100,000. The trucks were assembled, and 

pumps added by an equipment dealer in Fairbanks, for a final delivered cost of $175,000 each for 

the 100-barrel trucks and $300,000 for the 300-barrel truck.

Task D: Reinforce with Ice Chips

Ice chips are milled from a fresh water lake and then loaded and hauled to the ice road to

reinforce shore banks and the surface of the road. The ice chips are spread with the grader and

watered with the water trucks. This process will finish the road rapidly and is used for the last

five to ten days of road construction. The four to six operators are the pumper operators, as the

pumpers likely will not be used during this process. For 10 miles of ice road this task is assumed 

to be completed in eight days. For an ice island, with a slightly smaller volume of material to be 

added, but a greater travel distance for moving the fresh water and ice chips, this task is assumed 

to be completed in ten days.

The ice mill is a state, surplus, concrete Roto-Trimmer; it was modified, reconditioned, and a

large power pack added, for about $250,000. It is mounted on a loader or grader that was

purchased at an Anchorage based dealer for $200,000 each. Dump trucks are heavy-duty trucks 

purchased from in-state dealers at $50,000 to $100,000 each. The large grader was purchased

from a local dealer at $200,000.

Task E: Stake the Road

At about five days into Task A, pickups can safely be driven on the ice roads. Supervisors,

support personnel, and staking crews will then move on to the road. Reflector stakes are

installed at the roadsides to keep equipment on the road during periods of poor visibility. Stakes 

are installed by drilling a small hole in the ice and freezing them in place. Four men and two

pickups per 12-hour shift stake for four to five days. For 10 miles of ice road this task is

assumed to be completed in four days. For an ice island, with a much smaller surface area, this

task is assumed to be completed in only one shift on one day.
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The nine pickup trucks are heavy-duty crew cab fleet trucks and are purchased from a local

dealer who purchased them from a Washington State based fleet dealer for about $25,000 each.

Task F: Road Maintenance

The road is graded as needed by the large grader. Most winters this is continuous. Crews and

equipment are called back as necessary to repair the road and seal cracks. Stakes are replaced as 

needed. For 10 miles of ice road this task is assumed to require a full-time grader operator on

each shift and a staker for one shift each week. For an ice island, with a much smaller surface

area, this task is assumed to require a grader operator for one shift each week.

4.5 DRILL SHIPS, BOTTOM FOUNDED PLATFORMS AND SUB-SEA WELLS

The drill ship and bottom founded platforms and sub-sea wells modeled in this study represent

very similar technologies. In fact, the bottom-founded platform is essentially a drill ship that is

welded on the top of a large barge. The bottom-founded platform is more expensive to construct, 

owing to the need to purchase a salvaged barge and to attach it to the bottom of the drill ship. It 

has the advantage, however, that it can be placed on the sea floor and used as a longer-term 

structure for exploration and production purposes.

The mobile exploration platform and the bottom-founded production platform are also based on

the same set of technologies. Both begin with the drill ship welded on top of a salvaged barge. 

To convert the platform from a mobile exploration use to a permanent production use requires a

retrofitting that is identical to equipping a gravel production island.

The sub-sea well is also a related technology. The sub-sea well is similar to any well, except that 

it is drilled from a drill ship and tied back to the production island with a combination sea-floor 

and buried pipeline.

In each case, the drill ships and bottom-founded platforms are supported by a group of vessels

including an icebreakers, work boats, ocean-going tugs and fuel barges. The size and make-up 

of this auxiliary fleet will depend on the season and whether the operation takes place in an area 

of calm or rough waters. These activities are also supported by secondary activities including

helicopters and barges.

Data for this task was collected from several individuals. These included:

• An interview with an individual who worked as a geophysical data collector and on a 

drill ship.

• An individual who worked as a crane operator on a Sinkable Island Drill Ship (SIDS), as 

well as working for an ice road construction firm, an ice road maintenance contractor and 

as a ship Engineer aboard a support barge.
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• An individual who was an owner of a variety of arctic support firms including an ice road 

and island construction company, a barge support company, a Prudhoe Bay hotel. He 

also served as an equipment consultant.

The following sections provide information on the various technologies.

Drill Ships

Drill ships can be used for drilling in the summer months and when water depths are over 20

meters. They are used for drilling exploration wells and in conjunction with sub-sea wells. The

drill ship modeled in this study was based on the Canmar Drill Ship Explorer III. Canadian

Marine Drilling LTD or “CANMAR” has been instrumental in the development of most of the

Arctic drilling technologies.

An interview with an individual who worked as a geophysical data collector and on the Canmar

drill ship as a sample collector provided some background information. In this instance, the

Canmar drill ship was in operation about 200 miles west of Barrow, Alaska approximately 10

miles from Russian waters.

The drill ship had a 33-man crew, including the drilling crew, ship crew, and camp support. The

drilling rig was a top drive located in the center of the boat. It had a hydraulic system that

allowed the boat to move up and down, about 20 feet, with the drilling equipment staying fixed

to the bottom. The ship was held in position by eight anchor lines that were set by the three

support work boats with 6-man crews per boat. There was a class-4 ice breaker with a 16-man 

crew to clear the way to and from the site, and intercept large ice flows that could compromise

the drill ships position. If the seas became higher then the 20 foot limit of the drilling system, the 

well will be shut off at the ocean floor and the ship moved off the well and held in place by an

ocean going tug with a 4-man crew. A large fuel barge supplied fuel to all of the on-site 

equipment. There was also a 4-man diving crew for under water support.

Two 412 helicopters provide 2-hour trips daily to and from the Canmar to Barrow. A total of 6

men flew and supported the helicopters. On shore support required another 33 personal at

Barrow.

The permanent ship crew included the following personnel:

• 1 Captain

• 2 Mates

• 2 Engineers

• 4 Able bodied Seamen

• 1 Navigator
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In addition, the crew sizes for the additional support activities are as follows.

• Class 4 Ice Breaker (33 crew)

• Support from Three Work Boats (16 crew)

• Ocean Going Tug (18 crew)

• Fuel Barge (4 crew)

• Two Helicopters for Support (8 crew).

• Support from Divers (6 crew)

• Onshore Support (4 crew)

• Maintenance Support (15 crew)

• Camp Services Support (6 crew)

• Seal and Cap Well(s) with a Locator (12 crew)

• M.W.D.'s (2 crew)

• Sample Takers (2 crew)

• Observer (whale watch)

• Wire Line (2 crew)

It is assumed that standard drilling crews will be used in addition to the ships crews.

The average crew wage is about $7,200 per month with about 35 percent overhead for FICA,

taxes etc. Ship’s cost per man is about $45 per day for food, water, laundry, sewer processing,

etc. The crews work 12 hours on and 12 hours off and rotate crews every two weeks.

The amount of use of each of the support vessels and personnel were allowed to vary based on

the task under consideration. Note that separate scenarios of support vessel and crew needs were 

modeled for rough and calm waters. For sub-sea development wells, it was assumed that the

rough water scenario would be most likely due to the water depths. The full crews were used to 

move the equipment or to operate the drill ship in rough water. In calm water, none of the

support vessels were included with the exception of one fuel barge which was assumed to double 

as a work boat. In addition, the drill ship crew was cut in half, except for the captain who was

retained and the navigator who was not.

Fuel consumption for the full group of vessels was estimated at 1.6 million gallons of fuel for 30 

days under power. Fuel consumption for the workboats was estimated at 180 gallons per hour 

based on data collected for the sub-arctic model. Fuel for the other vessels was estimated based

on vessel size. The estimates were double the work boat rate for the drill ship, sea-going tug and 

fuel barge and the triple the rate for the ice breaker. The resulting fuel use roughly equals the

original estimate. These fuel use rates were also assumed to vary based on the activity. Fuel use 

for rough seas operations were assumed to be half of the use when underway. Calm seas use was 

assumed to be a quarter.

Mobile Exploration Platform and Bottom-Founded Production Platform
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Data for this task was collected from several individuals. One of these individuals worked as a

crane operator on a Sinkable Island Drill Ship (SIDS) as well as working for an ice road

construction firm, an ice road maintenance contractor and as a ship Engineer aboard a support

barge. Another individual was an owner of a variety of arctic support firms including an ice road 

and an island construction company, a barge support company, a Prudhoe Bay hotel. He also

served as an equipment consultant.

The SIDS is a very large barge equipped with a drilling rig. The ship is loaded with drill stem,

casing, drilling mud and all other major supplies necessary to drill several wells. It is then towed 

to a drilling site that has been prepared by a barge with a large crane to assure the bottom is free 

of large rocks and is fairly level. The SIDS is then positioned over the drill site and sunk to the

bottom (approximately 30 to 40 ft).

“Flex-a-barges” deliver day-to-day supplies. These barges are constructed with individual

sections that can be added or subtracted to change the barge size to meet the needs of the day.

Power drive sections can also be added or subtracted. The barges have a three- to four-man crew 

and can be used from mid-July to the first part of October. Ice road support can begin in January 

and continues until May. From October to January and May to mid-July only helicopter support 

can be used. The main difference between the SIDS and the Canmar is that the SIDS is bottom

based and most of the support vessels are not needed once it is set. The SIDS operates in 30 to 40 

feet of water and the Canmar drill ship can operate in open seas up to 600-feet deep.

As discussed in Chapter One, there are a variety of mobile bottom founded structures that have

been used or suggested for use in the arctic off-shore environment. These include:

• The Caisson Retained Island (CRI)

• The Concrete Caisson Island (Tarsiut)

• The Concrete Island Drilling Structure (CIDS)

• The Mobile Arctic Caisson (Molikpaq)

• Single Steel Drilling Caisson (SSDS)

• Sinkable Island Drill Ship

For the most part these structures are similar in design and economic impact. They consist of

salvaged steel structures, sometimes supplemented with concrete for ice protection, that are

towed or self propelled to the site and then ballasted with water or gravel. Ballasting with gravel 

is less likely because if the gravel becomes contaminated with oil, disposal of the material

becomes problematic as the gravel may be considered hazardous material. Depending on water

depth, these production structures may be placed on a gravel berm.

These structures become practical when water depths make the use of gravel islands

prohibitively expensive due to the required slopes.

These structures can be left in place permanently and equipped as production islands following

the same procedures and costs as for gravel islands.
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A bottom-founded drilling platform that will be used in the 2002 and 2003 drilling season is the 

AEC Oil and Gas (USA) Inc. SDC/MAT. This platform is used to model both the mobile

gravity exploration platform and the bottom-founded production platform. As stated above, the

Arctic Mobile Caisson platforms (Molikpaq) and other mobile platforms will model the same,

differing only in size and shape from the Sinkable Island Drilling Structure (SIDS).

The AEC SDC/MAT has been stored and modified in a western Alaska port since 1990. It is

now at the McCovey exploration site north of Prudhoe Bay in the Beaufort Sea. If exploration is 

successful it will be used as a production platform. The MAT is a slope-sided barge permanently 

mated to the bottom of a Steel Drilling Caisson (SDC), which is a modified “very large crude

carrier.” The SDC/MAT floats in 23 feet of water when at its lightest weight and in 68 feet of

water when loaded with normal fuel and provisions. The SDC/MAT gravity ballasts over the

site to a depth of 30 to 75 feet. As with most bottom-founded drilling platforms, bottom depths

below 75 feet require a sub-surface gravel island or dredged gravel berm.

Once this SDC is in place, service barges bring drilling and service supplies, including a pile

driver to drive 30 feet casings into the ocean floor through four available drilling slots. There are 

quarters for 104 crewmembers. Crews are moved back and forth to Prudhoe Bay by helicopter.

It will take about $120 million dollars each to modify the SIDS, CIDS, or the Molikpaq so they

could be used for exploration and production. These types of bottom-founded platforms have

proven the ability to take the winter ice movement and summer wind and waves fairly well;

however, just how much maintenance will be required over the long term is unknown at this

time.

As discussed above the SDC/MAT is a combination of a salvaged very large crude oil tanker

(The Liberia) that is welded on top of a barge. The Liberia has a weight of 82,859 tons. Based

on reported salvage values estimated at 23 cents per pound, the vessel would cost approximately 

$38 million. The MAT constructed barge has an estimated weight of 60,144 tons. At an

estimated 23 cents per pound, the vessel would cost approximately $28 million. In addition, the 

costs of moving this equipment to Port Clarence, Alaska which is at Tellar in Seward Peninsula

was estimated to be $20 million. Construction modifications were estimated to cost $130

million, while administration support was estimated to cost $20 million.

Sub-Sea Development Wells

Sub-sea development wells with trenched production lines were modeled. This technology

would most likely be used in multiple well, sub-surface caissons. Ice roads or drill ships would

access these caissons when necessary. A very high risk, due to access only part of the year, has

prevented this technology from being used and may prevent its use in the future.

The cost information is based on sub-sea well completions developed for Saklian Island. In this 

particular scenario, off shore crude was flowed to shore about 4.5 miles. The off shore water
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temperature was 27 degrees F. The pipe was wrapped with a protective coating that provided a

small insulation R-value. Wax build up from the crude closes the annular area of the pipe

creating an insulation R-value. Crude flows in the remaining annular area of the pipe;

consequently, the pipe is oversized to provide needed flow rates. Concrete donuts, cathodic

protection, and any control or instrumentation lines are installed and lowered as a unit to the

ocean floor. The donuts are installed every ten feet. This technology is recommended with high 

volume fast flowing wells only. Water temperature, crude composition, flow rates and pressure

contribute to the pipe size and distance crude will flow and how fast it will cool. In this scenario 

the crude is at ambient temperature in about 1 and 1/2 miles.

If the pipe comes ashore, the area of pipe subject to ice gouging or keeling (ice being pushed on 

shore) must be buried up to 21 feet deep depending on the soils, wind and ice conditions.

The buried pipeline costs and installation are the same as for the standard buried pipelines that

service the production islands. This technology is described later in this chapter.

The sea-floor portion of the pipeline will be constructed using the same technology as was

modeled in the sub-arctic. The sub-arctic pipeline lay barge will have to be used to lay the

under-sea portion on the sea floor with a multiplier of 2.2 for deep sea, such as the Chukchi Sea 

or Hope Basin.

4.6 HELICOPTER SUPPORT

The manpower and input vector estimates were developed for one day of helicopter support. For 

this activity it is assumed that the helicopter will be staged at the airport at Prudoe Bay. In the

IMPAK model the distance of the project from Prudoe Bay is entered. Based on the distance the 

time per trip is calculated. The number of trips is based on estimates of the number of trips

required per activity.

The budget rate for a helicopter and crew is $100,000 per month. This rate is for a long term

project requiring year-round support. For Northstar, the first offshore production project in the

Beaufort Sea, under construction in 2000, two helicopters and two crews are required. In

addition to the monthly fixed cost, there is a fixed fee of $950 per hour plus a federal

transportation tax of 10 percent for passengers or six percent for cargo. This cost includes fuel. 

Ninety percent of the flights are primarily for passengers.

The base daily cost for the helicopter, based on 12 months and 365 days would be $3,288 per

day. Based on information provided in the interviews and personal experience on the North 

Slope, the project engineering staff estimate the helicopters average three round trips per day at

1.5 hours per round trip or 4.5 hours a day. Note that this estimate of 1.5 hours per round trip

assumes a maximum trip length of 50 miles one way and that trip times can be adjusted by

distance using an assumed line-haul speed of 100 miles per hour. 
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The estimate of 4.5 hours of use per day would add an additional $4,275 per day to cover the

hourly fee. In addition, the weighted average passenger and cargo tax is calculated by

multiplying the $2,275 estimate by the tax rate of 9.6 percent. The result is a tax estimate of 

$410. An overall daily revenue estimate of $7,973 is found by summing the three estimates

together. Note that if all twelve seats were filled on all three flights, the one-way cost would be 

$111 per flight.

The analysis of the helicopter support activity is based on a series of interviews supplemented by 

the engineering and economic analysis experience of project staff. Interviews were conducted

with the following source:

• An employee of a larger helicopter service company in Alaska that was recently

awarded the contract to provide helicopter support to Northstar an offshore

production island.

Overview of the Activity

The helicopter used for this operation is a Bell 212 that will be staged at the airport at Prudoe

Bay. The Bell 212 can carry 12 passengers. From April to December, the season when the ice

roads are not functional, the helicopters are busier than from January to March when the ice

roads are functional. These helicopters can fly using instruments (IFR) which allows them to be 

used during inclement weather and at night. They can also be used for med-evac.

As discussed above, the helicopter would make more trips in the summer and less in the winter. 

In the summer, the helicopter would typically make one trip daily for crew change, one for cargo 

and a scheduled flight that is part of a sweep that will make stops at designated locations such as 

other islands or exploration sites.

The remainder of this section provides information on manpower, capital and material costs.

Manpower and Cost

According to the interviews, the helicopter support contract includes a full time hanger manager, 

a two member maintenance crew and two pilots that are on call 24 hours a day. The pilots can

fly 10 hours in a 24 hour day. If they need more coverage than that then they will need another 

crew. The charge out rate for a pilot is $500 per day. No wage rates were provided for the other 

personnel. According to the engineering project staff, the helicopter support staff and pilots

work two weeks on and two weeks off. All of the employees are Alaskan but there are no Native 

employees. 

Capital Cost

The 15-place Bell 212 is the twin-engine civilian version of the highly successful U.S. Army

"Huey" helicopter. This helicopter provides the additional safety of twin engines for offshore or
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remote area work. With the increased horsepower available, heavy payloads may be carried

under difficult climatic conditions.

The Bell 212 engines are twin Pratt and Whitney turbines rated at 1,025 horsepower for a single 

engine. The craft has a fuel capacity of 220 gallons with an auxiliary tank capacity of 180

gallons.

The helicopter is estimated to cost $5 million, not including delivery to the North Slope.

Fuel Use

A Bell 212 helicopter burns 100 gallons of fuel per hour. Based on the estimate of 4.5 hours of

flying time per day, total fuel consumption per helicopter is estimated at 450 gallons per day.

4.7 LOCAL BARGE TRANSPORTATION

The manpower and input vector estimates were developed for one trip by a support barge. 

Generally, the Beaufort Sea will allow use of barges for four months from the first of June to the 

first of October, limiting survey work to those months. Surveys can also be conducted on water, 

but this is generally not the case.

The average lease price per day for barge service, including crew, is $12,000 per day according

to the contractors interviewed for this study. These are actual operating costs and include all

applicable contractors overhead. It is assumed that no additional oil company or general industry 

overhead is assigned to this activity.

It is assumed, for purposes of calculation, that a barge trip takes one day so that the daily cost

and the per trip cost are the same. However, loading and transit times vary considerably, so it

this assumption should be critically reviewed for each project or activity under consideration. 

According to the sources interviewed, if the island is close and the items that were being hauled 

could be loaded and unloaded quickly, such as gravel, then the barge might be able to make two

trips a day. However, if the items were more difficult to load, such as piping that needs to be

cribbed, it would take most of a day to load and another day to unload so would take almost 3

days per trip. If the island is farther away, such as Northstar, then it will take about two days just 

to travel one way to the island. For this reason, barge support is best calculated as a cost per day.

In addition to barges, several other types of waterborne craft are potentially used on the Beaufort 

Sea. For example, in the previous manpower model supply boats and tugboats are both included. 

 According to the interviews conducted for this study, however, neither is used for local

transportation on the Beaufort Sea. There used to be a supply or support boat a few years ago

but most of the islands or sites where located in shallow water 6 to 10 feet deep and the boat

would become grounded. As production activities move farther from shore, into Federal waters, 

then there might be a use for them in the future. In addition, there are currently, no tugs staged at 
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Prudoe Bay. Tugs are used for the big barges from Anchorage. Only the smaller self-propelled 

barges are used locally.

The analysis of the local barge activity is based on an interviews supplemented by the

engineering and economic experience of project staff. Interviews were conducted with the

following sources:

• An owner of a marine firm

• A partner in a marine industry Limited Liability Corporation (LLC)

Overview of the Activity

The remainder of this section provides the engineering information that was collected from the

interviews and other sources. Included is general information on the activity and as well as more 

specific information on capital, labor and material inputs.

The support barges that were modeled are Robaushaw Flex-I floats made in Louisiana. They are 

made of individual float sections that are pinned together and can vary in configuration. As a

model, costs were developed for a 40' by 120' barge with two self-propelled power units and

self-contained crew quarters. The barges are shallow draft and haul 400-tons. The original

purchase price was $1.2 million. The barge is occasionally refurbished and updated as

necessary. It is estimated that total capital costs are on the order of $100,000 per year.

There is also generally some additional capital equipment that is staged at the dock. For

example, there might be a 966 Cat loader. On an island, if special equipment is needed such as a 

crane then it will be included in the contract. If pallets of drilling mud are being moved, for

example, then a forklift will be needed. Other than the loader, it is assumed that no specialized

loading or unloading equipment or employees are used as part of this activity. Instead,

specialized tasks are assumed to be performed using the equipment and labor for the activity that 

is being assisted by the barge.

The two power units use diesel fuel at the rate of 3 gallons per hour each or 6 gallons in total. 

The barges are assumed to be in motion 12 to 16 hours a day. At 16 hours per day, which would 

cover some lesser fuel use while not in motion, fuel use would be 96 gallons per day. The cat is 

assumed to use 150 gallons per hour and to be used an average of eight hours per day.

The crew for such a vessel is estimated to consist of four individuals. These include a captain, a 

ship engineer and two laborers. The captain and engineer are paid approximately $400 per day

while the laborers are paid $300 per day. 

The barge is assumed to operate 24 hours a day and to make two trips a day. Operating 24 hour 

is made possible due to the summer season and 24 hour day light in the arctic. According to our 

sources the captain sleeps while the barge is being loaded and unloaded, the laborers sleep while 

the barge is underway and the engineer sleeps whenever he can. Given the 24 hour operating
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schedule the barge is able to make a round trip per day. As the unit of analysis for this activity is 

a round-trip, costs are on a daily basis.

4.8 WELL DRILLING

The development of oil and gas resources require a variety of well drilling activities including

the drilling of exploration wells, delineation wells, production wells, service wells and waste

wells. In addition, well workovers, which are a maintenance activity performed every five years 

or so, are required to maintain optimal flow. For the purpose of this study, well drilling is

divided into three activities with separate manpower and input vector estimates developed for an 

exploration well activity, a production well activity and a well workover activity. This is similar 

to the previous manpower model, except the former model did not include a well workover

activity. 

The MMS E&D scenarios use a somewhat different categorization scheme. The first difference

is that exploration wells are divided between exploration and delineation wells. Also, the E&D

scenarios refer to production wells as production and service wells. A final difference is that no 

explicit mention is made of well workovers. The E&D scenarios also do not mention waste

wells.

In this study, no separate estimates are provided for waste, spoils or tailings disposal wells. A

separate activity for spoil disposal was contemplated, but was later dropped. According to the

interviews conducted for this study, spoils (drilling tailings) are usually ground up and injected

back into the well under high pressure as part of the driving force used to bring the crude oil up

to the surface. As spoil disposal is part of the production process it is included in the daily cost 

of well drilling (it is a function of the drilling rig). Where spoils refer to waste disposal such as

sewage waste, then this is injected into a separate well. The waste well may only take 4 to 5

days to drill. Since this activity is so small and takes a similar amount of time as a well

workover, the model will assume that for every production island constructed, a well workover is 

immediately performed.

The costs for well drilling activities are based on a quoted cost of $107,000 per day for the

drilling of production wells. Per well estimates are then derived by multiplying the daily

estimate by the number of days required to drill each type of well. The development of the

estimates for exploration wells and well workovers required adjustments in the amount of labor

and materials and equipment purchased. For example, well workovers require less materials,

more specialized personnel and are sometimes conducted with a smaller more portable drill rig

often mounted to a truck. As adjustments were made to the costs for exploration wells and well 

workovers, the costs per day of these activities were allowed to vary from the rate quoted for

production wells.
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The analysis of the well drilling activities is based on a series of interviews supplemented by the 

engineering and economic analysis experience of project staff. Interviews were conducted with

the following sources:

• An employee of a well drilling company currently working on the North Slope

• A former sales representative for a well drilling equipment supply company

Overview of the Activity

During the life of an exploration or production project, a number of drilling contractors may be

used. Each one uses their own drill rigs and crews. The drilling company provides the drill rig

and personnel to operate the drill rig. The oil company provides what goes in the well.

The cost to run a drilling camp is $107,000 per day. Of this total, approximately $75,000 per day 

is for the labor and drilling and $32,000 per day is the cost of tangible materials, which includes 

expenditures for casings, tubing and well heads. It does not include the costs of other materials

that go into the well such as mud, cement and drilling fluids, which are customarily supplied by

the well owner.

Usually a given drill rig is kept on site during the entire construction of the facility. A waste well 

and about half the production wells and gas injection wells are drilled prior to the start of

production and then wells are continually drilled and repaired (worked over) during the

remaining production phase.

Typically it takes 3 to 4 weeks to drill a production well and one day to move from one well to

another one on the same island. It takes approximately 4 to 5 days to move a new rig onto an

island and set it up using an ice road and an equal amount of time to remove an existing rig off

an island. To move drilling rigs is usually bid by lump sum. The same crew that operates the

drill rig moves the rig from well to well and from site to site. For the purpose of this study, it is 

assumed that it takes 30 days to drill the average production well. This estimate is assumed to

cover the time required for both transportation and drilling.

An exploration well will take at least 2 months and up to 4 months to drill depending on the

conditions that they encounter. The midpoint of this range of 3 months (90 days) was assumed

in this study. However, there is a great deal of variability in the cost and time spent drilling

exploration wells. At $107,000 per day an exploration well would cost only $9.6 million,

however, according to the interviews conducted for this study, a dry hole can cost up to $28

million and a potential hole that has extensive testing performed and can go up to $40 million

The test holes are abandoned in place at a depth of 20 feet below sea level. The rig is already in 

place, so it becomes a matter of removing the production tubing and setting plugs as required on 

the way out. It is assumed the time required for abandonment is included in the ninety days.
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A well work over usually takes 4 to 5 days and often uses a smaller drill rig, but a more

specialized crew. A well work over will almost never require replacing the casing, but usually

replaces or repairs production tubing, packing, etc. (the "jewelry"). Due to the variability of

activities and problems addressed by workovers it was difficult to obtain a reliable estimate of

the average cost for a workover, but staff engineers believe that it would be reasonable to assume 

the same daily rate as a new well.

Assuming four days for a workover and the same daily cost as for other well activities of

$107,000, results in a cost estimate of $430,000. Another interviewee that worked up on the

North Slope a few years ago quoted a range of $200,000 to $500,000. For this study, the

estimate of $107,000 per day was used as a starting point, but reduced as necessary to reflect

reductions in material requirements. Capital costs were kept the same based under the

assumption that the smaller rig would cost less, but have a lower utilization rate. Labor

requirements were also left the same assuming the reductions in costs for crew size would be

offset by the cost of more specialized crew.

According to the sources interviewed, every well will get at least one workover during its

lifetime. Typically, a well may be worked over 3 to 4 times in its 20-year life. For modeling

purposes, it will be assumed that each well receives three workovers, one every five years after 

initial construction. These well workovers are in addition to the initial proxy for a waste well.

Manpower and Cost

A typical drill camp would require 30 to 35 people to run the drill rig and 10 to 15 service and

support personnel. A larger camp may have 50 people to run the drill rig and 20 to 25 service

and support personnel. Two work crews stay on the island for two weeks and work 12-hour 

shifts then two new crews replace them for two weeks. Typically a drilling crew will have 85

percent Alaskan employees with 2 to 4 percent Natives. There is one drilling company that is a 

Native company that uses about 50 percent Native hires.

For study purposes, an average of 22 workers per shift, two shifts per day, replaced every two

weeks is assumed, including 14 service and support and 30 operators. The occupations and

costs per day for each worker are described below. Each occupation is required on each shift, so 

if the drilling supervisor is required and receives $800/day then there is a counterpart on the next 

shift who also receives $800 for another shift on the same day.

The service and support people each shift and their pay rates include:

• Drilling supervisor ($680/day)

• Directional driller ($580/day)

• Electronics ($580/day)

• Mudder/cementer ($480/day)

• Casing worker ($480/day)

• Spill technician ($530/day)
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• Medic ($580/day)

Drill Rig Operators each shift and their pay rates include:

• Pusher ($680/day)

• Motorman ($580/day)

• Derrick hands (2) ($530/day)

• Mechanic ($530/day)

• Welder ($530/day)

• Electrician ($530/day)

• Roustabout (8) ($480/day)

The Roustabout is either an apprentice for an above position or general laborer. Total direct

labor costs are $12,100 per shift or $24,200 per day.

Capital Equipment and Cost

A new rig costs about $20 million and may last 10 to 15 years and may be refurbished 3 or 4

times during its life. The costs of refurbishing over the lifetime of a rig was not available from

the interviews, but were estimated by engineering staff to total approximately half of the original 

purchase price. The cost of the rig does not include transportation to the North Slope, so the cost 

of transportation had to be estimated.

Besides the drill rig, other equipment required to support the drilling operations would include a 

front-end loader, forklift, two pickups and a van to move equipment and people. The van was

not included in the capital estimates for this activity as it is assumed to be purchased by the

general personnel transport activity and is included here as a labor-related cost.

The front end loader and the forklift are assumed to be 966 Cats. As estimated in the seismic

survey chapter, these vehicles each cost $260,000 in Anchorage with an additional $10,000 for

arctic preparation and $3,000 for shipping to the Slope. This equipment lasts about 10 years and 

then has to be replaced or rebuilt. The pickup trucks are the same variety as those examined for

ice roads. Those pickup trucks were heavy-duty crew cab fleet truck and were purchased from

an Anchorage dealer from a Washington State based fleet dealer for about $25,000. This

equipment is estimated to have a four year life.

Material Cost and Consumption

There are two major groups of material costs. The first are the materials that become part of the 

well such as the well head casing and production tubing. The second are the materials used in

the drilling of the well such as the drilling fluids, drilling muds, cement and fuel.

The first group of materials which include the well head, casing and production tubing cost

approximately $960,000 for a production well. The well head (a series of valves to connect or
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isolate the well from the flow line) costs approximately $50,000. The casing and production

tubing cost $910,000. The casing is standard grade steel pipe and the production tubing is higher 

strength and more corrosion resistant. The degree of strength and corrosion resistance required

depends on the chemical composition of the crude and pressure required to extract the product. 

Casings and production tubing are not reused, but are usually abandoned in place.

The relative cost of the casing and production tubing were not available from the interviews, but

the cost of the casing per foot was estimated by sales representative to be significantly more than 

the cost of the tubing. This greater cost is due to the larger diameter of the casing. This greater 

weight also adds to the shipping cost.

According to the interviews conducted, casing and tubing is generally used in exploration wells

in order to test flow and to retrieve samples. However, there were some unresolved

inconsistencies among interviewees as to the relative costs and amounts of casing and tubing

materials used versus a production well. As a rough estimate it is assumed that casing and tubing 

costs for exploration wells are equal to those for production wells on an aggregate basis, but only 

one-third the cost on a daily basis.

For well workovers the casing and tubing is already in place. In some instances the workovers

will require repair or replacement of the tubing. However, as the replacement rate is thought to 

be quite low, no costs for casing and tubing are assigned to this activity.

The other major materials consumed are drilling fluids, muds, cements and fuel. The cost of the 

drilling fluids, muds and cements were estimated by the interviewees to be in the range of $2,000 

to $5,000 per day. At the recommendation of the study engineers, the midpoint cost of $3,500

per day was used.

Estimates of fuel consumption were based on the numbers of each type of equipment and their 

fuel consumption. There are two types of drill rigs, electric and mechanical. Both types are

powered by diesel fuel. In the case of the mechanical rig, all pieces of equipment, including

generators, pumps etc., are run directly on diesel fuel. In the case of an electric rig, diesel fuel is 

used to run 2 to 3 turbines that provide electric power to run the various pieces of equipment. 

According to study engineers, the electric type drills are no longer used extensively on the North 

Slope. The turbines each use about 70 gallons of fuel per hour at full load, but on average load

use about 94 gallons per hour in total. In contrast, the mechanical drill rigs use about 47 gallons 

per hour for exploration and production and about 27 gallons per hour for workovers. Based on

a 24 hour day, estimated daily fuel use is approximately 1128 gallons for exploration and

production rigs and 648 gallons for workover rigs.

The loader and forklift (966 Cats), as described in the seismic survey chapter, each consume 150 

gallons of fuel per day. The pickup trucks, as described in the ice road chapter, each consume 30 

gallons of fuel per day. All of the equipment is assumed to be used for exploration and

production activities. With the exception of the rig, no capital equipment is assumed for

workovers.
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Based on the above assumptions, daily fuel use is estimated at 1488 gallons for exploration or

production and 828 gallons for workovers. Total fuel use would be 133,920 for drilling an

exploration well, 37,200 gallons for drilling a production well and 2,592 gallons for a well

workover.

4.9 GRAVEL PRODUCTION ISLAND

The manpower and input vector estimates were developed for the construction of an offshore

gravel production island. Separate vectors were developed for the placement of the gravel and

for the placement of the erosion protection and other systems. This was done to allow the depth 

of water in which the island is constructed to vary.

A large production island will have a working surface of approximately 450 feet by 450 feet that 

is 16 feet above low water. For the sand and gravel placement activity, it is assumed that the

island will be built by enlarging an existing exploration island. This was the case for Northstar,

and for cost reasons, making use of existing islands or natural features is a preferred course of

action. In 40 feet of water, 1.2 million cubic yards of gravel will be required for the island. 

Assuming that 400,000 cubic yards are in place at the existing island then an additional 800,000

cubic yards will be required. By way of comparison, Northstar required 700,000 cubic yards on

top of a former exploration island that had been abandoned six years earlier. In the IMPAK

model, alternative water depths can be entered. The model calculates the amount of sand and

gravel required. The ratio of this volume to the volume required in 40 feet of water depth is used 

to scale the input vector.

The construction of this type of island can be performed during the winter construction period

(December to May) using ice roads or by barge during open water. Winter construction is the

preferred method and is modeled in this chapter.

To build the gravel island will require an average of 60 personnel. The gravel will be mined

from a gravel pit using conventional earth moving equipment and moved to the edge of the sea. 

When the offshore ice road is completed the gravel will be trucked to the island, spread and

compacted. These tasks are modeled in the first activity.

The island will have erosion protection consisting of filter fabric and pre-cast concrete mats. 

Also, sheet piling will be installed on four sides of the island with tail walls that tie-in to provide 

support. Finally, concrete foundations for the modules will be added as will a concrete helipad. 

These tasks are modeled in the second activity.

The analysis of gravel island construction costs were based on a series of interviews

supplemented by the engineering and economic analysis experience of project staff.
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Overview of the Activity

The island will be accessed by ice road during the winter construction period. A large

production island will have a working surface of approximately 450 feet by 450 feet that is 16

feet above mean lower low water level (MLLW). A submerged gravel berm 75 feet wide at 15

feet below MLLW protects the island from deep ice flows and causes premature breaking of

waves. The seabed is approximately 40 feet below MLLW. Storm surges may raise the mean

water level 4 feet above the MLLW.

The gravel is mined from a gravel pit (typically within a dry riverbed) using conventional earth

moving equipment. The gravel mine site will be prepared by removing snow and waste material 

using large graders, front end loaders and dozers. Dozers with a ripping tooth will loosen the 

gravel bed for excavation and blasting may be required. Blasting would require drilling 200 to

300 holes at 10 feet on center 20 feet deep and then simultaneously detonating a charge in each

of the holes.

The gravel will be moved from the mine site as soon as the tundra is frozen, and onshore ice road 

can be built, and stock piled onshore until the offshore ice road to the island is constructed. 

When the offshore ice road is completed the gravel will be trucked to the island, spread and

compacted. The sea ice from around island would be cut and removed as required to place the

gravel using standard earthmoving equipment.

Once the gravel is in place erosion protection and sheet piling will be installed around the

perimeter of the island. The erosion protection will consist of concrete blocks placed on top of

fabric. Finally, concrete footings that will serve as foundations for the production modules will

be put in place as will concrete blocks that will serve as a heliport.

The following paragraphs discuss each of these major activities (gravel work, concrete work,

fabric placement and sheet piling) in detail. Estimates of labor, capital and materials are

provided for each.

Gravel Mining, Hauling and Placing 

Information was collected on the equipment that is used in constructing a gravel island and the

costs of purchasing, retrofitting, refurbishing and shipping the equipment to the North Slope. 

Information that was not available from the field data collection effort was estimated as

described in the capital equipment section below. The following information was collected:

At the mine there will be the following equipment:

• Two 988 CAT front end loaders ($520,000 each, $10,000 arctic equipment, $3,000

shipping).

• One 966 CAT front end loader ($260,000 each).

• One D-10 CAT dozer ($720,000 each, $7,000 arctic equipment, $3,000 shipping).
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• One D-7 CAT dozer ($360,000 each).

On the island there will be the following additional equipment:

• One 966 CAT front end loader ($260,000 each).

• One D-7 CAT dozer ($360,000 each).

• Two large graders ($200,000 each).

• Two compactors ($250,000 each, $7,000 arctic equipment, $3,000 shipping).

To haul the gravel there will be the following equipment:

• 16 Euclid B-70s (purchased used for $60,000 to $70,000 each and refurbished for

$30,000).

The number of Euclid B-70s required was calculated in the following manner. The trucks have a 

capacity of 60 to 70 cubic yards. They will make 6 to 7 loads per shift or 12 to 14 per day. To

move 800,000 cubic yards in 2 months, which equates to 13,000 cubic yards/day and at 65 cubic 

yards/trip and 13 trips/day (845 cubic yards/truck/day), requires 16 trucks.

To build the gravel island (excluding erosion protection, concrete work, fabric work and piling)

will require approximately 60 personnel. These are total labor requirements and the labor force

will be split between two 12 hour shifts). Labor would be housed at a hotel/camp facility and

bused to the work site. The construction would be continuous 24 hours a day seven days a week.

 The crews would work two weeks on and two weeks off. The construction period would take 2 

to 3 months.

The manpower that would be required each shift for gravel mining, trucking and placement

would include:

• Supervisor (3) ($600/shift)

• Equipment operators (24) ($500/shift)

• Maintenance (2) ($500/shift)

• General laborer (2) ($480/shift)

The daily total cost for the 31 person crew would be $15,760. For both shifts, the estimates

would double to 62 employees and $31,520. Approximately 85 percent would be Alaskan hire

and 10 percent Native hire.

In addition, the state royalty for the gravel is $1 per cubic yard or $800,000. The total estimated

cost to mine the gravel, haul and compact is $20 per cubic yard or $16,000,000 per island.
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Concrete Work

A variety of concrete work will be required on the production island. All of the concrete will be 

pre-poured into blocks and other shapes and barged to the island. The concrete work will

include blocks for erosion protection, footers to serve as foundations for the production modules 

and blocks to form a helipad. The cost of North Slope concrete work, based on the past

experience of project engineering staff, is $800 per cubic yard finished in place.

Protection of the island will require the installation of erosion protection consisting of filter

fabric and pre-cast concrete mats. This will require approximately 27,000 square yards of filter

fabric and 15,000 pre-cast concrete blocks (four feet by four feet by nine inches thick). The

concrete blocks would be fabricated on the North Slope at Deadhorse, using aggregate from the

North Slope’s Oxbow mine and cement and additives from Fairbanks and Anchorage. It would

require approximately 30 people and 4 months to pre-fabricate the blocks.

The completed concrete blocks would interlock using cable and shackles. A string of blocks

would be tied together, stacked and barged to the island. The completed concrete blocks would

interlock using cable and shackles. It is estimated that 45 barge trips would be required to move 

the concrete blocks and 55 people to install. The total cost for this operation would be $5.4

million.

Concrete foundations (spread footings) for the production modules to be placed on will be

produced at Deadhorse and installed on the island. The estimated cost of the module foundation 

concrete work is $500,000. In addition a concrete 55 feet by 55 feet helipad will be constructed 

at a cost of approximately $90,000.

Summing the $5,400,000 for the concrete blocks, $500,000 for the concrete foundations, and

$90,000 for the heliport, results in estimated total of $5,990,000 in concrete work. The following 

is a breakdown of the costs for materials, labor and capital:

• Material: 7,500 cubic yards at $200 per cubic yard $1,500,000

• Labor: 55 people for 120 days at $495/day

• Supervisor (4) ($600/shift) $ 288,000

• Equipment operators (38) ($500/shift) $2,280,000

• Maintenance (4) ($500/shift) $ 240,000

• General laborer (8) ($480/shift) $ 460,800

• Equipment:
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• Mixing plant - $45 per cubic yard $ 336,500

• Barges - 45 trips, 45 days, $12,000 per day $ 540,000

• Two 30 ton cranes, 90 days $ 130,000

• Two front end loaders, CAT 966, 90 days $ 65,700

• Two back hoes, 450 Hitachi, 90 days $ 93,000

• Two cement trucks, 45 days $ 16,000

• Eight pickups, 120 days $ 40,000

• Total $5,990,000

Fabric Erosion Protection

The total installed cost of the fabric will be approximately $270,000. The fabric material itself

will cost about 30 percent or $81,000. It comes in 20 foot wide rolls and will be installed by the 

same equipment used for the concrete block installation. A crane or front end loader will be used 

to lift it up and roll it out, just before laying down the concrete blocks. A breakdown of costs for 

materials labor and capital is provided below:

• Material: $81,000

• Labor: 4 people per shift for 30 days

• Supervisor (2), $600 per day $36,000

• Operators (4), $500 per day $82,800

• Laborers (4), $480 per day $82,800

• Equipment:

• One 30 ton crane, 30 day lease $21,950

• One front end loader, CAT 966, 30 day lease $10,950

• One pickup, 30 day lease $2,500

• Total $270,000

Sheet Piling with Tail Walls

Typically, this task will be performed using flat sheets with tail walls. The sheets weigh 31

pounds per square foot. The material and shipping cost (Manufactured in Texas, truck to Seattle, 

train to Fairbanks, truck to Deadhorse, truck to job site) is $0.45/lb. The installation cost is $43 

per square foot.

Sheet piling will be placed on all four sides of the island and the island is 450 feet by 450 feet in 

size. The sheet piles will be 40 feet in height, (20 feet bury, 10 feet soil backfill, and 10 feet

clear). The tail walls tee in to the wall to provide tie-in support and add forty percent to the total 

square footage.
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The quantity of sheet piling required is calculated by multiplying the 450 foot length per side of 

the island times the 40 feet in height times the four sides of the island and adding on 40 percent 

for the tail walls. The result is an estimate of 100,800 square feet.

The weight of sheet piling is 31 pounds per square foot. Multiplying the estimate of 100,800

square feet by the 31 pounds per square foot, results in an estimated 3,125,000 pounds. Given

material and shipping costs of $0.45 per pound, results in a total delivered material cost of $1.4

million.

The installation cost for 100,800 square feet at $43 per square foot is $4.3 million for a total of

$5.7 million.

To install the sheet piles in frozen ground a typical method is to drill 6 inch wide holes 20 feet

deep at 18 inch on center intervals. The holes are then filled with 180 degree water. The next

morning the ground is thawed enough to drive the piles into the ground using a hammer

supported by a crane. It is estimated that the piles will be installed in 90 days; working 7 days a 

week, two shifts per day, 12 hours each shift. The equipment and labor required is as follows:

Equipment:

• One Crane - Manitowoc 450 $350,000

• One hammer $195,000

• One CAT 966 front end loader $260,000

• Two Drilling machines $200,000

• One hot water truck $175,000

• Two pick-ups $ 25,000

• Two generator sets (lights) $ 5,000

• One mechanics truck $ 50,000

• Two welding machines $ 7,000

• Three templates (guides for piles) $ 15,000

Materials:

• Weld rods ($5 per man hour of welders)

The labor for each shift includes:

• Foreman (1) ($600/shift)

• Crane/pile operator (1) ($500/shift)

• Pile bucks/welders (4) ($430/shift)

• Mechanic (1) ($480/shift)

• Loader operator (1) ($500/shift)

• Drillers (2) ($500/shift)
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• Truck driver (1) ($500/shift)

Fuel Use

The following data on fuel use was collected from the interviews for this task and were

supplemented by fuel use data collected for other activities.

For the gravel mining task, the following equipment will be used for 60 days:

• Three large Cats (988 and D-10) (8.33 gallons per hour/200 per day)

• Two small Cats (966 and D-7) (6.25 gallons per hour/150 per day)

For the gravel placing task, the following equipment will be used for 60 days:

• Three large Cats (988 and D-10) (8.33 gallons per hour/200 per day)

• Two small Cats (966 and D-7) (6.25 gallons per hour/150 per day)

• Two large graders (6.25 gallons per hour/150 per day)

• Two compactors (6.25 gallons per hour/150 per day)

For the gravel hauling task, the following equipment will be used for 60 days:

• Sixteen trucks (3.75 gallons per hour/90 per day)

For the concrete work, the following equipment will be used for 90 days except as noted:

• Two 30 ton cranes (10 gallons per hour/240 per day)

• Two Cat 966 front end loaders (6.25 gallons per hour/150 per day)

• Two back hoes, 450 Hitachi (10 gallons per hour/240 per day)

• Two cement trucks, 45 days (3.75 gallons per hour/90 per day)

• Eight pick-ups, 120 days (1.25 gallons per hour/30 per day)

For the fabric work, the following equipment will be used for 30 days:

• One 30 ton cranes (10 gallons per hour/240 per day)

• One Cat 966 front end loader (6.25 gallons per hour/150 per day)

• Two pickups (1.25 gallons per hour/30 per day)

For the sheet piling task, the following equipment will be used for 90 days:

• One Manitowoc 450 Crane (10 gallons per hour/240 per day)

• One hammer (25 gallons per hour/600 per day)

• One CAT 966 front end loader (6.25 gallons per hour/150 per day)

• Two Drilling machines (8 gallons per hour/192 per day)
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• One hot water truck (3.75 gallons per hour/90 per day)

• Two pick-ups (1.25 gallons per hour/30 per day)

• Two generator sets (lights) (5 gallons per hour/120 per day)

• One mechanics truck (1.25 gallons per hour/30 per day)

• Two welding machines (5 gallons per hour/120 per day)

4.10 EQUIP PRODUCTION ISLAND

The manpower and input vector estimates were developed for equipping a single production

island. In addition, the estimates developed for the transportation and installation portions of this 

activity will be used in developing the manpower and input vector estimates for the abandonment 

activity. According to project engineering staff, the costs of installation will be similar to the

costs of removal.

The gravel production island will be equipped with two infrastructure and two process modules. 

The costs of fabrication and installation of these modules are modeled on those that are currently 

planned and under construction for the Northstar Island. Northstar has space for 27 wells and

water flood and gas re-injection are planned. Northstar oil production facilities will be built in

Anchorage at the Port of Anchorage and barged to the North Slope

The infrastructure modules will include a quarters and a utility module. In addition, the

infrastructure modules will be supported by 10 conexs, a diesel and a water tank, three flares, 15 

pipe racks and 20 well houses.

The process modules include a processing facility and a compressor module. The process

modules are supported by a warehouse/shop facility and two tanks for fuel and start up fluids.

Support equipment will be staged on the island prior to arrival of the modules by sea lift. These 

include cranes, trailers, rig mats and steel plates that will be used to transport the modules over

the island gravel. Once the modules arrive, they will be unloaded from the barges, installed on

the foundations and hooked up.

The analyses of the costs of equipping the island were based on a series of interviews

supplemented by the engineering and economic analysis experience of project staff. Interviews

were conducted with the following sources:

• A manager with one of the firms constructing the modules for Northstar.

• The owner of a marine transportation firm.

• Sales representatives for several heavy duty equipment manufacturers.
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Overview of the Activity

The process of equipping the production island has two major components. These include:

• Fabricating the modules; and

• Transporting and installing the modules.

The remainder of this section provides information collected on the manpower, capital and

material costs for each of these major components.

Module Fabrication

As was the case for Northstar, it is assumed that the modules will be fabricated in Anchorage. 

The Northstar project represents the first time that the modules were constructed in Alaska,

however, absence information to the contrary, it is assumed that this trend will continue. The

fabrication will take approximately a 16 month period, using an average manpower of 250 and

peak manpower of 350. The workforce will be predominately Alaskan. Assuming 16 months at 

30 days per month and an average of 250 employees, results in an estimated 120,000 man-days 

to fabricate the modules and load them on the barges. At an estimated cost of $300 a man day,

fabrication labor costs will be approximately $36 million.

In addition, it is estimated that the Port of Anchorage will be upgraded with (2) 300-ton cranes,

(3) 45-ton hydraulic cranes and new offices to support this fabrication effort.

The following specifications were used in costing the materials and purchased equipment

required to build the infrastructure modules:

• The permanent quarters are designed to hold 75 personnel including 20 to 25 core

operations and 50 for the drilling operation. The quarters are 60 feet long by 60 feet

wide by 40 feet high

• The utility module has a capacity of 14,400 gallons per day. The module is 60 feet

long by 60 feet wide by 35 feet high. It will house the following functions:

a. A potable water treatment system for treating 9,360 gallons per day of

potable water using a single distillation type desalination process. It will

also have equipment for treating a similar amount of wastewater using

single fixed-media activated sludge treatment (FAST) with ultraviolet

light disinfecting.

b. A washdown water system capable of partially treating 5,040 gallons per

day and injecting it directly in the disposal well.
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c. An emergency power system consisting of two 1,230 kilowatt diesel

generators for a combined 2.46 megawatts.

• Ten conexs, which are 8 by 8 by 20 foot steel storage boxes similar to a railroad box 

car or shipping container. Six of the conexs will be used for consumables and tools

and four for construction materials.

• Miscellaneous equipment including two tanks to hold diesel fuel and water, three

flares, 15 pipe racks and twenty well-houses.

The cost data collected and estimated for the materials and major pieces of purchased equipment 

needed to construct these modules include the following:

• The permanent quarter’s module which is 60 feet by 60 feet and four floors tall will

cost approximately $1,800,000 including structural, mechanical, electrical, and

furnishings.

• The utility module which is 60 feet by 60 feet will cost $1,200,000 for structural,

mechanical, and electrical. In addition it will house a potable water treatment system 

that will cost $156,000, a washdown water treatment system that will cost $75,000, a 

wastewater treatment system that will cost $225,000, and an emergency power

system consisting of diesel generators that will cost $3,780,000.

• Ten conexs that will cost $8,000 each.

• Two tanks for diesel and water that will cost $30,000 each.

• Three flares, which are a big radio tower type steel structure with a flame at the top,

which are used to release pressure. They will cost $200,000 to $300,000 each.

• Fifteen pipe racks that will cost $5,000 each.

• Twenty well houses including the house and trim that will cost $106,000 each.

The following specifications were used in costing the process modules:

• The primary crude processing facility is designed to separate the gas and water from

the oil. This module is made from steel construction and is 240 feet long by 80 feet

wide by 90 feet high. It is built in two sections and attached in place. It has a total

weight of 6,000 tons.
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• The compressor module is designed to compress gas for re-injection into the

reservoir. It is made with steel construction and is 125 feet long by 80 feet wide by

55 feet high. It has a total weight of 2,500 tons.

• The warehouse/shop facility is 150 feet long by 60 feet wide by 35 feet high.

• In addition, there are two tanks for holding fuel and start-up fluids.

The cost data collected and estimated for the materials and major pieces of purchased equipment 

needed to construct these modules, includes the following:

• The process module will require approximately $7,680,000 in materials and

equipment. This includes $384,000 in steel structural materials, $768,000 in

electrical devices and supplies, and $768,000 in mechanical components including

heating and ventilation including duct work and insulation, but not including piping. 

In addition, there will be five major systems. These include: (1) $864,000 for the

inlet manifold system including piping and valves; (2) $1,440,000 for the oil and

water and gas separator system which is a large vessel; (3) $1,440,000 for the oil

treatment system which is also a large vessel; (4) $864,000 for a set of big pumps to

push product through the pipeline; and (5) $1,152,000 for miscellaneous piping,

instrumentation, chemical injection, small pumps and valves.

• The compressor module will require approximately $11,672,000 in materials and

equipment. This includes $192,000 in steel structural materials, $384,000 in

electrical devices and supplies, and $384,000 in mechanical components including

heating and ventilation including duct work and insulation, but not including piping. 

In addition, there will be five major systems. These include: (1) $6,680,000 for two

32,000 HP gas injection turbines; (2) $1,440,000 for a dehydrator system; (3)

$1,440,000 for a natural gas liquids (NGL) recovery system that separates out

butanes, etc. for mixture with the sales oil ; and (5) $1,152,000 for miscellaneous

piping, instrumentation, pumps and valves.

• The warehouse/shop that will cost $2,700,000.

• Two tanks for storing fuel and start up fluids that will cost $50,000 each.

Transportation, Installation and Hook up

The modules will travel by barge from Anchorage to the production island. Travel time will be

one month in each direction with two weeks for unloading. Three barges will be required at

$75,000 per barge or $225,000 in total.

The entire operation of offloading from the barges and then installation and hook up of the

modules will take three months with manpower of 140 persons at the peak. Personnel will be
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mobilized daily via boat or helicopter as the majority of this work will be done during the

summer open water season.

Most of the construction equipment required for module offloading will be transported to the

island via local barge from Prudhoe Bay. Two barges will be required. Diesel fuel for the

construction equipment will come from Prudhoe Bay by local barge and will be transferred to the 

permanent diesel storage tank facilities on the island. In addition, the support equipment used to 

move the modules and set them in place, including rig mats and steel plate for transporting the

modules over the island gravel, will be staged on the island prior to seal lift arrival. 

The off-loading equipment will include one 300 ton crane, two Cat 966 loaders, two 45 ton

hydraulic cranes, and a special module transport trailer. This trailer is 16 feet wide by 400 feet

long and will have 108 tires. It will either be transported form Anchorage in one piece by barge 

or in parts on several trucks. Although nearly every year large modules are sea-lifted or trucked 

from Anchorage to the North Slope, the operators do not keep such a trailer on hand at Prudhoe

Bay and reuse it as necessary. According to engineering staff, this is because there is no other

use for the large trailer, so it is only brought up when needed. It will be primarily used to

transport the compressor module and the process module. The latter is so large it will be in two

pieces.

The cost data collected or estimated to offload the modules from the barge includes the

following:

• Equipment: As listed above there will be three cranes, two 966 loaders, the large

trailer, rig mats, steel plate. In addition four pickups will be on the island for the

course of the installation and hookup operation. The cost of all the equipment for the 

period of time used was estimated by engineering staff to be $360,000.

• A crew of 50 persons, 25 on each shift, will be employed for the offloading portion of 

the activity. They will work two weeks on and two weeks off.

• Supervisor (4) ($600/shift)

• Equipment operators (10) ($500/shift)

• Equipment maintenance (4) ($500/shift)

• Technicians, welders, electricians, etc. (20) ($500/shift)

• General laborer (12) ($480/shift)

The workers for this task will be paid a combined $25,160 per day or $12,580 per shift.

Installation and hookup of the modules will be a labor intensive task involving piping and

electrical work along with small structural projects such as installing decking, walkways and 

passageways. Members of the installation crew will rotate into this crew as well and will be

augmented with additional employees that will include specialized personnel to work with the

various systems.
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• The cost of all the materials and equipment for the 120 days required for installation

and hookup was estimated by engineering staff to be $2,600,000. Ten percent of this 

total was estimated to be for equipment and the remainder for materials. Of the costs 

for materials, about 30 percent or $ was for piping, and 30 percent for fittings and

valves and other piping related materials and supplies. Another 25 percent was for

electrical components and systems, materials and supplies. The remaining fifteen

percent was for structural shapes, siding and roofing, doors and windows.

• Equipment: The two smaller hydraulic cranes will remain for this task as will the two 

loaders and four pickups. Also, two small forklifts will be added to the fleet. Eight

welders will also be required. The large crane will no longer be needed. The cost of

all the equipment for the period of time used was estimated by engineering staff to be 

$260,000.

• A crew of 120 persons, 60 on each shift, will be employed for the installation and

hookup portion of the activity. They will work two weeks on and two weeks off.

• Supervisor (8) ($600/shift)

• Equipment operators (12) ($500/shift)

• Equipment maintenance (8) ($500/shift)

• Technicians, welders, electricians, etc. (60) ($500/shift)

• General laborer (32) ($480/shift)

The workers for this task will be paid a combined $56,320 per day or $28,160 per shift.

All major tools and equipment related to construction and installation will be removed from the

island upon completion.

4.11 PRODUCTION ISLAND OPERATIONS

The manpower and input vector estimates were developed for the annual costs of day-to-day 

operation of a production island. Once the island is constructed, the wells drilled and the

production modules and other facilities installed, there will still be a need for an ongoing crew to 

staff the island. Their duties will include operating the systems, maintaining the equipment, and 

ensuring safety. In addition, the staff performing these functions will be supported by additional 

staff that will perform housekeeping functions. These housekeeping personnel will staff a

complete housing function similar to the onshore hotel/camp facility.

Total manpower for the production island activity will be approximately 62 persons, half on each 

shift. Materials that will be consumed will include food and housekeeping goods, diesel fuel,

natural gas, and materials for maintenance and other functions.
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The analysis of production island operation costs were based on a series of interviews

supplemented by the engineering and economic analysis experience of project staff.

Overview of the Activity

The majority of the capital equipment needed to operate the island, including production

modules, living quarters, heliports and docks are assumed to be put in place during the Island

Construction and the Island Equipment Installation activities covered in previous sections of this 

chapter. Once the island is constructed and equipped, annual expenditures will be required for

the next twenty to thirty years in order to operate and maintain the production infrastructure.

While most of the capital equipment is already installed, the exception is several pieces of

general construction equipment that will be permanently stationed on the production island. This 

includes four pickups, two Cat 966 front end loaders, a utility van and a crane.

In addition, the operation of the production island will require daily expenditures for the

following items:

• Manpower

• Food and Housekeeping Supplies

• Diesel Fuel

• Natural Gas

• Other Materials and Supplies

The expenditures for these capital, labor and material inputs are discussed in more detail in the

following paragraphs.

Capital Equipment and Cost

Eight pieces of capital equipment are assumed to be permanently stationed on the production

island. These include the following:

• Four heavy-duty pickup trucks ($25,000 each as estimated in the ice road chapter)

• Two CAT 966 Front End Loaders ($260,000 each as estimated in the gravel island

chapter).

• One utility van ($50,000 as estimated in the general passenger transport chapter)

• One crane ($520,000 base cost plus $7,000 for arctic retrofit and $6,000 for shipping)

Manpower and Cost

Approximately 62 persons, 31 per twelve hour shift, are required for the operation of the

production island. The rotation pattern is two weeks on and two weeks off. The occupations of 

the 31 crew members per shift and their daily pay rates are as follows:
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• Cooks/Maids (6) $380

• Water/Waste treatment (1) $500

• Maintenance (1) $500

• Supervisor (1) $650

• Facility Engineer (1) $620

• Maintenance Foreman (1) $600

• Lead Operator (1) $550

• Expediter (1) $500

• Operator (3) $500

• Maintenance (2) $480

• Roustabout (3) $430

• Well Operator (1) $530

• Crane Operator (1) $500

• Compressor Maintenance (1) $500

• Welder (1) $500

• Welder Helper (1) $430

• Electrician (2) $500

• Instrumentation (2) $500

• Safety Officer (1) $430

Each shift of 31 workers is paid $14,840 in combined wages per day. For both shifts the

estimate doubles to $29,680.

Fuel Consumption

Fuel use includes the fuel used for the vehicles, diesel fuel used for a backup generator, and

natural gas used to power the main turbines to run the production island modules. The fuel use

for the pickup trucks and the van was assumed to be only 25 percent of normal due to the small

size of the island, intermittent use, and increased idle time. The fuel use for the Cats and the

crane was assumed to be only 50 percent of normal for the same reasons.

The following data on fuel use were collected from the interviews conducted for this task and

were supplemented by fuel use data collected for other activities as noted.

• The heavy duty pickups use 30 gallons per day as reported for the ice road activity.

• The Cats use 150 gallons per day as reported for the seismic survey activity.

• The van uses 30 gallons per day as reported for the seismic survey activity.

• The crane uses 120 gallons per day.

• The emergency generator, which is used in the event of an interruption in natural gas 

supplies, uses 150 gallons per day.

In addition, natural gas is imported through the pipeline system to serve the various natural gas

fired turbine generators, compressors and pumps that are part of the modules installed on the
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island. In the early stages of the life of the production island, the island will import significantly

more natural gas than toward the middle and end of operations. On average, it is estimated that

$48,000 per day of natural gas will be consumed. In some sense, the expenditure is an

accounting practice only, as the natural gas is actually produced and consumed by the same

company.

Food and Housekeeping Supplies

Food and housekeeping supplies are assumed to be identical to those consumed at the onshore

hotel/camp, with the possible exception of slightly higher transportation costs to transport these

items out to the island.

For the hotel/camp, the raw cost of food per person per day was estimated as $12 with one-third 

of this cost for transportation. The food is then prepared on-site. Laundry is hauled back and

forth to Fairbanks where it is processed once a week. The total cost for laundry and

housekeeping supplies is $1 a day per person. Personal laundry is done in laundry equipment on 

the island. It is estimated by study engineering staff, that one-half of the laundry and supplies

cost is for transportation and that 75 percent of the remaining cost is for laundry and the balance 

for housekeeping supplies.

Miscellaneous Materials and Supplies

There are a variety of chemicals, spare parts, tools, small appliances, valves, gauges and

miscellaneous materials and supplies consumed on the island each day. It is impossible to

estimate either an exact amount expended on these items or an exhaustive list of the items

consumed. As a best guess, an estimate of $10,000 per day or $3,650,000 per year was used. A 

list of potential items was developed along with a rough estimate of costs for each item. As this 

process only covered about half of the estimated dollars, the estimates for each item were scaled 

upward on the theory that the items omitted were likely to be similar to the items included, or as 

least it was likely they might be bought from the same IMPLAN sector.

4.12 LOCAL GAS PRODUCTION

Local gas production in Arctic areas such as the Hope Basin would be a scaled down version of a 

sub-sea production well and the pipeline to shore scenario. The process would use a smaller

drill-ship, smaller diameter piping, a narrower set of trenches, smaller size concrete anchors, less 

welding and smaller size crews. Engineering staff for this study estimate that the costs,

depending on the amount of local gas needed, is approximately 50 percent of an oil production

well and gas pipeline to shore. This rule-of thumb estimate is based on the assumption that local 

use would be about the same as Barrow’s.

In addition, a dedicated gas production facility would be required. The gas production facility 

cost was based on the cost of the gas module for the sub-arctic oil and gas processing facility. In 
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this case the gas module accounted for one-sixteenth the cost of the facility. As a rule of thumb, 

one-sixteenth the cost of constructing and operating the facility was used. The facility is

assumed to be powered by the gas produced by the facility. During operation the facility is

assumed to require the use of one heavy-duty pickup that is operated one-quarter time.

4.13 OFFSHORE AND ONSHORE PIPELINES

The manpower and input vector estimates were developed for ten miles of each type of pipeline. 

 Separate estimates were made for offshore pipeline and onshore pipeline due to differences in

the techniques employed, equipment used and the cost of constructing the pipeline. In particular, 

the offshore pipeline is buried under the sea floor while the onshore pipeline is elevated on steel 

supports known as vertical support members (VSMs).

Pipeline construction is conducted by contractors hired by the oil companies. The total installed 

cost for offshore pipelines is about $7 million per mile ($70 million per ten mile segment), while 

onshore pipelines cost considerably less in the range of $3.4 million per mile ($34 million per ten 

mile segment). These are actual construction costs. 

The ten miles of pipeline is estimated to take two to three months to construct, whether it is

offshore or onshore. The midpoint of this range, 75 days, was assumed in developing all of the 

estimates in this chapter.

In estimating distances and costs for pipeline construction, it is important to consider already

existing infrastructure. For example, the onshore pipelines for Northstar will use existing

supports and an existing gravel service road for eight of the 11 miles. This will reduce the

onshore cost by $10 to $12 million dollars. For the estimates developed in this study, it is

assumed that no preexisting infrastructure is used.

The analysis of pipeline construction costs were based on a series of interviews supplemented by 

the engineering and economic analysis experience of project staff. Interviews were conducted

with the following sources:

• A manager with a construction company that holds the pipeline construction contract

for Northstar.

• An engineer who served as a consultant to a construction company on several

pipeline construction contracts.

• A mechanical engineer familiar with pipeline coating costs.

• Sales representatives for three heavy duty equipment manufacturers.
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As discussed above, the construction techniques employed for offshore versus onshore pipeline

construction are quite different. The following paragraphs describe the general techniques used

to construct each type of pipeline. Additional subsections provide engineering descriptions of

the capital, labor and material inputs to the production process.

Overview of the Offshore Pipelines Activity

During the construction of offshore pipelines, a 200 foot wide ice road is used along the pipeline 

as a work pad. The road is thick enough to support the heavy equipment used to install the

pipeline (about 10 feet thick). A Ditch Witch trencher is used to cut a ten-foot wide trench in the 

ice. Another trencher cross cuts the ice into blocks that can be lifted out of the water with a

thumb hoe. The blocks are then moved to edge of the ice road with a bucket loader, so that their 

weight won't affect the trench. A bridge section is placed across the trench with modified

backhoe on it. The backhoe is capable of reaching up to 70 feet down. The bridge, with the hoe 

on it, is pulled with a D-7 winch tractor. As the hoe excavates the ditch the spoils are loaded on 

a spoils truck with a bucket loader and hauled to an area where the pipe has been lowered in the 

trench. Another bucket loader places the spoils back in the trench over the pipelines. 

A tie in weld shack is mounted on a D-6 tractor. The tractor contains two welding machines and 

a generator to run lights, heat and a coating machine. The coating that is used is baked epoxy 25 

mil thick or polyethylene. The tractor also has a boom to place the next section of pipe to be

welded and coated at the weld section. The other end of the section to be welded on is held with 

a D-7 side boom tractor. This process is duplicated for the gas pipeline at every section so that

the two pipelines can be bundled together. Anodes are installed at the time of bundling. The

completed pipeline bundle is then moved to, and lowered in the trench with three D-7 side boom 

tractors. As stated above the spoils are then placed back in the ditch. The equipment is serviced 

and supported by a maintenance and survival station, consisting of a generator, mechanics

module, lube and fueling module and a survival module. The total installed cost is about $7

million per mile. 

Overview of the Onshore Pipelines Activity

The path of the onshore pipeline is covered with a standard 60 foot wide onshore ice road to

protect the tundra. A Texoma drill is used to drill 24 by 20 inch deep holes every 50 feet. Ten

inch piles are placed in the holes, wedged in place and back filed with slurry mixed in a concrete 

truck. Cross arm pipe supports are welded on the piles with one cross support member on top of 

one pile. This completed assembly is called a vertical support member or VSM. The VSMs are 

subcontracted at $10,000 each installed, or about $1 million per mile. The same D-6 tractor

mounted welding shack that is used for the offshore pipeline is used to weld, coat and insulate

sections of the pipe together. A D-7 side boom holds the other end of each section. Three D-7 

side boom tractors lift the lines onto the VSM's. The installed price of the two pipelines (gas and 

oil) is $3.4 million per mile.
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Pipeline Capital and Equipment Costs

The equipment is dedicated 20 percent to each of the pipeline activities. This level of dedication 

factor is typical for the Northstar project. Information was collected on the equipment used and, 

where available, the costs of retrofitting, refurbishing and shipping the equipment to the North

Slope. Information that was not available from the field data collection effort was estimated as

described in the capital equipment section below. The information collected was as follows:

• Ditch Witch: A model 8020-T trencher has a cost of $160,000 base plus $15,000

arctic upgrade and $3,000 shipping. The ditch witch is used to cut the ice for offshore 

pipeline construction only. Three are used in total, two on each side of the 10 feet

wide trench and one transverse. They are not used for onshore pipeline construction.

• Thumb hoe: The "thumb hoe" is a Hitachi model 450. It is a tracked backhoe with a 

hydraulic thumb that opposes the bucket and is used to pickup the ice blocks. It cost 

$370,000 plus $3,500 for arctic upgrade. As an alternative it can be rented for

$24,000 per month. One is used for offshore construction, but none are used onshore.

• Texoma drill: This equipment was estimated to cost in the range of $350,000 to

500,000. The Texoma Drill is used onshore only.

• Bucket loader: A Cat 966 has a cost of $260,000 base plus $7,000 arctic upgrade and 

$3,000 shipping. Three bucket loaders are used offshore and two onshore.

• Bridge section: The bridge section is constructed at Prudhoe from steel and rig mats

for $30,000. Two are used for offshore construction, but none are used onshore.

• Cat D-7 winch tractor: The winch tractor is estimated to cost $360,000 base plus

$7,000 arctic upgrade and $3,000 shipping. One is used for offshore construction, but 

none are used onshore.

• Modified backhoe trencher: The "modified backhoe trencher" is a Hitachi model 450, 

cost $370,000 plus $3,500 arctic upgrade plus $130,000 for the long reach front end. 

Two are used for offshore construction, but none are used onshore

• Spoils truck: A suitable truck transporting spoils might be purchased used at Prudhoe 

for a base price of $60,000 and refurbished for an additional $40,000. The spoils

truck is used offshore only.

• Concrete slurry truck: The cement truck costs $130,000 plus $10,000 for arctic

upgrade ($8,000 for insulated drum and $2,000 for insulated and heated water tank)

and $3,000 shipping. The cement truck is used onshore only.
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• Cat D-6 mounted weld shack: The cost of the Cat D-6 is $300,000 plus $7,000 for

arctic upgrades and $3,000 for shipping. The cost of the weld shack including

lighting and heating is $150,000. Two of each are used offshore and one onshore.

• Coating machine: The coating machine costs $25,000. Two are used offshore and

one onshore.

• Cat D-7 side boom tractor: The side boom tractor is estimated to cost $370,000 base 

plus $7,000 arctic upgrade and $3,000 shipping. Five D-7 Side Boom Tractors are

used offshore and five onshore.

• Cat XQ 225 self-contained generator unit: The base cost of this unit is $72,000 plus

$8,000 for arctic upgrade and $3,000 for shipping. One of these units is used for both 

offshore and onshore operations.

• Atco skid mounted modules: The modules cost $27,000 each delivered to Prudhoe

Bay. One of these units is used for both offshore and onshore operations.

Material Costs

Purchased materials include the pipe, the coating for the pipe, the anodes and the cement. Cost

data that were collected from the interviews include:

• Offshore pipe per line: A set of two pipes are installed with the cost per mile for the

pipe at $170,000 per mile plus $126,000 per mile for shipping and $30,000 per mile

for coating.

• Onshore pipe per line: A set of two pipes are installed with the cost per mile for the

pipe at $170,000 per mile plus $126,000 per mile for shipping, $30,000 per mile for

coating and $35,000 per mile for insulation.

• Cement: The material cost for cement slurry is $300 per cubic yard or $600 per pile

or $60,000 per mile. Cement is used onshore only.

• Anodes: The cost of anodes, assuming one every 50 feet and including the cost of

continuous cathodic protection, is $68,000 per mile. Cathodic protection is used both 

offshore and onshore.

• VSMs: The material cost and margins for VSMs include $3,500 material and $6,500

for labor. The VSM’s are used on shore only.
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Fuel Use

The following data on fuel use was either collected from the interviews for this task and were

supplemented by fuel use data collected for other activities as noted.

• The ditch witch will use five gallons per hour or 120 gallons a day.

• The thumb hoe burns six to 15 gallons of fuel per hour, an average of nine gallons per 

hour or 216 gallons a day.

• The modified backhoe trencher burns 6 to 15 gallons of fuel per hour, an average of

10 gallons per hour or 240 gallons a day.

• The Texoma drill will use seven gallons per hour or 168 gallons a day

• The CAT XQ-225 self contained generator unit will burn 12 gallons per hour or 288

gallons per day.

• The cats use 150 gallons per day as reported for the seismic survey activity.

• The trucks use 90 gallons per day.

Manpower and Cost

The crews used for offshore and onshore vary significantly with the offshore crew much larger

due to the cost of cutting and moving the ice and digging the trench. The offshore crew has

approximately 42 employees while the onshore crew has 24 members. There are three crews for 

each activity, with one crew working, one crew sleeping and one crew on leave. Rotation is four 

weeks on and two weeks off.

The occupations of the 40 offshore crew members and their pay rates are as follows:

• Project manager (1) ($645/day)

• Environmental Engineer (1) ($645/day)

• Superintendent (1) ($605/day)

• Foreman (1) ($600/day)

• Operators (19) ($500/day)

• Mechanics (2) ($500/day)

• Oiler (1) ($500/day)

• Laborer (2) ($480/day)

• Welder (4) ($500/day)

• Fitter (4) ($500/day)
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• Inspector (2) ($500/day)

• Coater (4) ($500/day)

The 42 offshore pipeline crew members per shift are paid $21,455 in combined wages per day. 

For both shifts, the estimates double to 84 crew members and $42,910 in total daily wages.

The occupations of the 24 onshore crew members and their pay rates are as follows:

• Project manager (1) ($645/day)

• Environmental Engineer (1) ($645/day)

• Superintendent (1) ($605/day)

• Foreman (1) ($600/day)

• Operators (9) ($500/day)

• Mechanics (1) ($500/day)

• Oiler (1) ($500/day)

• Laborer (2) ($480/day)

• Welder (2) ($500/day)

• Fitter (2) ($500/day)

• Inspector (1) ($500/day)

• Coater (2) ($500/day)

The 24 onshore pipeline crew members per shift are paid $12,455 in combined wages per day. 

For both shifts, the estimates double to 48 crew members and $24,910 in total daily wages.

4.14 SEA FLOOR PIPELINES

This task was developed primarily from an interview with the Alaska Planning Manager for

Forrest Oil Corporation. Forrest Oil is drilling the Redoubt Shoals development in the lower

Cook Inlet and operates the Osprey platform. The information for this task is based on offshore

pipeline construction for that project. It is adjusted to account for the different wage rates and

work schedules in the Arctic. In addition, concrete donuts are assumed to be used.

The pipelines to the Osprey will be assembled on shore and pulled with tugs to the platform. 

OCS deep-water production platforms will require a lay-barge, as the pipe can not be pulled. 

The cost per unit will be about the same for either method. However, the lay-barge and crews

are all from the lower 48 states, as no lay-barges are licensed in Alaska. Cook Inlet pipelines

vary in diameter from eight to 16 inches.

Specific installed costs are listed below. Using a chart of weights and dimensions of seamless

welded pipe, an estimating formula was developed by project engineering staff for pipeline

fabrication. This will cover various coatings, geographic considerations and equipment

variations. The formula is as follows:
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Installation Cost Per Foot = (pipe weight per foot in pounds @$2.00 per pound) +

($60.00 per foot for fabrication) +

($37.50 per foot for offshore installation)

This activity ignores real estate easement purchases or permitting, as they vary greatly per 

installation.

Pipeline Installation

 

According to the estimation formula, pipelines of 8, 10, and 16 inches in diameter can be

installed at $140.50, $168.50, and $263.50 per foot.

Onshore Equipment

The onshore fabrication equipment has a ten-year lifetime and therefore costs will be capitalized 

over a ten-year period and will prorate at about $ 0.32 per foot per $100,000 of original

investment or about $29.50 per foot for this example.

Equipment used onshore for pipe fabrication includes the following. One 966 Caterpillar loader 

with forks and bucket that costs $260,000 for the base model plus $5,000 for Alaska upgrade. 

Four D6 side boom caterpillars that cost $330,000 each for the base model plus $5,000 for

Alaska upgrade. Two pickup trucks at $25,000 each from a local fleet dealer. Two 20 ton

cranes at a cost of $260,000 each. Two welding trucks (fully equipped with welders, torches,

and tools) at $34,000 each.

Offshore Equipment

Offshore equipment such as tugs, dive boats, and lay-barges are leased by the day for pipeline

installation. Some of these boats have been in service for over 30 years, so that calculation of

lifetimes and capitalization of costs would be difficult. Each of four tugs has two 55 hundred

horse engines and two generators. The fuel consumption is 180 per hour at $1.50 per gallon.

This tug leases for $10,000 per day. Each of the two 50 feet by 12 feet dive boats has two 1000 

horsepower engines, a generator and an air compressor. The dive boats consume 40 gallons of

fuel an hour.

This activity involves “dragging” the pipelines from shore to the platform. A large onshore

staging area is prepared where the pipe will come ashore. Four 40-foot pieces of pipe are welded 

in sections and their joints are coated and wrapped. The 160-foot sections are stacked in the

staging area until they are to be dragged off shore. The previously welded sections of pipe are

carried to cribs on the beach by the side boom D6 Cats. The 20-ton cranes hold the ends being 

joined until they are welded and the joints coated and wrapped.

The pipes are then pulled by the tugs towards the platform they will serve. Several platforms

may manifold to one that has pipelines going ashore. The divers look for abnormalities in the
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ocean bottom that could stress the pipe. Each set is 160 feet long and about five sets on each

pipeline can be placed in a 12-hour day. The onshore equipment is serviced and fueled before

and after work and at lunchtime if necessary. The equipment uses about 600 gallons of fuel per 

day at $1.50 per gallon.

In addition to the materials used for the sub-arctic pipeline, in the arctic environment concrete

donuts are installed around the pipe and lowered as a unit to the ocean floor. The donuts are

installed every ten feet. The costs of making the concrete donuts are based on the concrete work 

for island protection systems discussed above.

Personnel

All personnel work 12 hours a day for 7 days a week. The composition of the pipeline crew

includes:

• 1 Construction Manager

• 6 Operators

• 2 Welders

• 2 Pipe fitters/welders helpers

• 2 Laborers

• 4 Divers

Offshore crew that operate and live aboard the tugs work a two week on and two week off

schedule averaging 12 hours per day. The crew of the tugs and lay barges include:

• 1 Captain

• 2 Mates

• 1 Engineers

• 1 Helpers

• 2 Seamans

• 1 Cooks

Note that this is the crew for a single shift on a single tug/laybarge. There are four vessels and

two shifts.

The crew of the dive boats consists of a Captain, Mate and Engineer. In this case, two divers

per boat at $800 per day each will be used. If a lay-barge is used, the onshore crews and

equipment will work on the barge. As discussed above, the costs per unit for the two

construction techniques are very similar.

The concrete crew includes the following personnel:

• 2 Supervisors

• 19 Equipment operators
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• 2 Maintenance personnel

• 4 General laborers

There are two shifts of these employees.

4.15 LAND BASE OPERATIONS

The manpower and input vector estimates were developed for an onshore land base. This land

base provides storage of materials, storage and maintenance of vehicles, hauling and logistics. 

The portion of this operation that is assigned to a given year of a lease development scenario is

specified in the E&D scenario.

The North Slope has what has been referred to as a $1 billion warehouse operation that supports 

all of the oil exploration and production activities. This operation is unlike any in the world,

because of the lack of a normal supply chain due to the remote area. BP and Phillips both have

large warehouse facilities at Prudhoe Bay and Kuparuk. There are also approximately 12 smaller 

warehouses and storage areas at the other oil fields.

The E&D scenario for lease 170, which was used extensively in the design and testing of the

model and data developed in this study, estimates that the land base will only be used during

major construction years in 10 percent increments. However, it is worth noting that since this

operation supports all of the ongoing operations, and since North Slope oil production is about

1,250,000 barrels per day, such that an island that produced 25,000 barrels per day would

represent two percent of the total production. Project engineering staff has suggested that one

could assume that such an island would use two percent of the land based support. During

construction the support required by the island may increase to 3.5 percent.

The estimates developed in this chapter assume that capital costs for the construction of the

facility are sunk and are therefore not included in the estimates. This provides the most accurate 

estimate of economic impact, because it is unlikely that the activities to be modeled will require 

the construction of new land base facilities.

The analysis of land base operation costs were based on a series of interviews supplemented by

the engineering and economic analysis experience of project staff.

Overview of the Activity

These North Slope warehouses have everything that is needed. There are no other sources of

materials so these warehouses are stocked like a very large hardware store with pumps, valves,

pipes, gaskets, tools, clothing, toilet paper, light bulbs, etc. Warehouses in Anchorage would

also support the North Slope warehouse system.
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There are lots for equipment rentals including front end loaders, graders, trucks, pickups, cranes

(10 to 50 ton), bulldozers, etc. They won't have any big cranes (300 ton) that could unload the

drilling rigs or process modules. Another company (Kodiak Haulers) also hauls most of the

equipment to the remote sites. BP and ARCO won't actually own any heavy equipment on the

North Slope; however they will have a large fleet of pickups (pickups, vans, SUVs, i.e. light duty 

trucks). In addition, there is maintenance operation for the heavy equipment and the light duty

trucks.

Other companies have contracts to warehouse and supply the food and fuel for the slopes.

The land base system is assumed to comprise of two main warehouses, one for each major oil

company, and approximately 12 smaller warehouses spread out near the various production

facilities.

Capital Equipment and Cost

It is very difficult to estimate the amount of money spent to maintain the land base facilities or

the amount spent per year to keep them up-to-date. As a rough estimate, it is assumed that on

average $2 million is spent each year to add new buildings to the complex and $5 million is spent 

for maintaining the capital stock.

In terms of equipment, it is assumed that there is a fleet of 40 pickups, SUVs etc. maintained by 

the oil companies. Each of the large warehouses is assumed to have 5 forklifts and 2 CAT front 

end loaders while the small warehouses have 2 forklifts and 1 Cat a piece. In addition, it is

assumed that there is a fleet of 12 single unit flat bed trucks and 8 tractor trailer flatbeds with

half of this fleet at each of the 2 large warehouses.

A summary of the vehicles and their numbers and cost include:

• 16 Cat 966 front end loaders

• 12 flatbed single unit hauling trucks ($80,000 base plus $5,000 for arctic upgrade)

• 8 flatbed combination hauling trucks ($120,000 base for the tractor plus $5,000 for

arctic upgrade and $30,000 for the trailer)

• 22 forklifts

• 40 heavy-duty pickup trucks ($25,000)

Manpower and Cost

The large ware houses are assumed to have a staff of 30 each shift and the small warehouse a

staff of six each shift. For the large warehouses, on each shift there will be with two supervisors, 

four mechanics, seventeen operators and six laborers/clerks. For the small warehouses there will 

be one supervisor, three operators and one mechanic and one laborer/clerk. For all of the

warehouses, the total labor on both shifts and the daily pay rates will be as follows:
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• 32 Supervisors ($600/shift)

• 40 mechanics ($500/shift)

• 140 operators ($500/shift)

• 48 laborers/clerks ($480/shift)

In total there will be 260 workers earning $132,240 per day.

Heating Fuel Costs

It is assumed that the warehouses will have their own generators that run on diesel fuel. At the

large warehouses it is assumed that two generators are maintained to provide backup in case one 

fails. In addition, the warehouse will be tied into the local power grid and provides or takes

electricity when necessary. The smaller warehouses are assumed to have a single generator and

to rely solely on power from the local grid if their generator fails.

The raw costs are for operating the generator are 7.5 cents per kilowatt hour. It is estimated by

study engineering staff that the two generator sets would cost about $375 per hour to operate 

with $175 of this cost for capital, $150 for fuel, and $50 for miscellaneous material inputs

including oil, antifreeze, “clean sweep” and other inputs including rags. Since a total of sixteen

generators are assumed to be used by the 14 warehouses, costs will be eight times these estimates 

or $3,000 per hour.

Vehicle Fuel Costs

The following data on daily fuel use by vehicle type were collected from the interviews for this

task and were supplemented by fuel use data collected for other activities.

• The cats use 150 gallons per day.

• The single-unit trucks use 60 gallons per day.

• The combination tractor trailers use 90 gallons per day.

• The forklifts use 30 gallons per day.

• The heavy-duty pick-up trucks use 30 gallons per day.

4.16 SPILL CONTINGENCY

The manpower and input vector estimates were developed for a typical spill contingency

operation. This operation continues year round, but the equipment that is used varies by area

protected and the time of year.
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Clean Seas, a co-op funded by all of the oil companies involved in North Slope operations,

provides the spill protection and cleanup services for spills on land, rivers and offshore. The

coop is funded by 13 oil companies that contribute funds in proportion to shares of ownership in 

oil and gas production. Ninety percent of the expenditures are for maintenance, training and

capital. Only 10 percent of expenditures are for the actual cleanup activities which are referred to 

as oil spill contingency response. Most actual spills are extremely small, often a gallon or less.

The co-op covers about one-third of the North Slope land area and the adjoining Beaufort Sea. It 

is estimated by project engineering staff to be large enough to provide cleanup capability for

potential oil spills for approximately ten production facilities onshore and offshore. Therefore,

for modeling purposes, each production island will be assigned one-tenth of the costs of the spill 

containment co-op developed in this chapter.

These costs assume that OCS oil is brought to shore by a newly constructed pipeline that ties into 

existing pipeline infrastructure connecting to Pump Station 1 of the Trans-Alaska Pipeline

System. A spill could occur at any point between the production facility and Pump Station 1. 

This includes pipelines crossing land and rivers. OCS oil mixes with non-OCS oil between the

production facility and some point onshore. We assume a portion of Clean Seas costs are

attributed to the OCS.

The analysis of the spill contingency operation is based on several interviews supplemented by

the engineering and economic experience of project staff. One member of the engineering

project staff was trained in spill operations while working on the North Slope. Interviews were

conducted with the following additional sources:

• An owner of the firm that constructs the new onboard motor river boats that will be

used in the operations. This individual also maintains boats currently used in these

operations and trains the boat operators.

• An owner of a firm that builds the air boats used in spill contingency operations.

Overview of the Activity

There are three types of spill contingency that include: river protection, open sea water

protection and spring and fall freeze and thaw protection. A description of each of these types of 

spill contingency is provided in the following paragraphs followed by information on manpower, 

capital and material costs.

River Protection

River protection is relevant to both offshore and onshore activities. They apply to offshore

activities because associated production facilities, such as Alpine, are sometimes located on a

river delta or because the onshore portion of the pipelines that service offshore activities might

cross a river and river protection would be necessary if there were a pipeline leak.
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The major equipment for rivers includes eight 24-foot Marion aluminum river boats powered by

200 hp Yamaha outboards. In the case of the Clean Seas Co-op, two are owned by the co-op, 

while six are owned by the oil companies and assigned to the co-op. The company that produced 

these boats is out of business and these boats are not as environmentally friendly as newer

equipment. They will be replaced by new boats with inboard engines within five years. The new 

river boats are 22 foot Silver Streak boats with 360 hp inboard jet boat engines.

In spring, when rivers thaw out, the crews drive the boats up to the river and carry booms and

anchor them on river banks. Booms are plastic floats filled with air. They contain the oil and

prevent it from continuing downstream. Four sets of booms are put in place 400 yards apart. 

The booms are left in place all summer. If a spill occurs, eight boats and crews are sent to the

river (one hour to get there) with eight people per boat. Each boat retrieves one end of a boom

and goes to the middle of river and hooks their boom together with the boom from the opposite

side of the river. To practice containing the oil spills, the spill contingency teams practice with 

oranges.

Another important piece of equipment is the oil/water skimmer/separator. These are also staged 

on the river banks with the booms. There is one skimmer for every two booms. The booms are 

first used to stop the oil from flowing downstream. The boats then stop to pick-up the skimmers. 

 The skimmers are basically a belt with paddles (like a conveyor belt). It has floats and is

powered by gasoline. It also has an oil and water separator that works by pumping the oil off the 

top and the water off the bottom. The oil is put in barrels or double walled bladders.

Each river or island has its own set of equipment, as it is impractical to go too far for equipment 

given the importance of quickly containing the oil. If a river has several rigs near it or pipelines 

crossing it, it will have a set of booms below each.

Open Sea Protection

The major pieces of equipment for open sea protection are two 42 foot ocean going boats. They 

are staged at a dock in Prudhoe Bay. If a spill occurs they go to the site and hook two booms

together and circle the site of spill. Booms generally come in 100 foot lengths and there are

2000 to 4000 feet on each boat. The crews start down wind from the oil spill and spread the

booms out to contain the oil spill. They may not close the loop. The boats then disconnect and

go inside of the booms to the contained oil and use the same skimmers/separators as are used for 

the river protection task. The process may be repeated if oil gets over the boom. One difference 

between the open sea and river operations is that all of the equipment is stored on the boats.
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Spring and Fall Protection

During the fall and spring freeze and thaw periods the river and open sea boats cannot operate. 

As a result, air boats are used. Other than the type of boat, the process is the same as for the

other methods. The air boats carry the booms and the skimmers/separators. The air boats can

run effectively on ice, snow, or water.

Manpower and Cost

Clean Seas has 108 permanently employed people who maintain the boats and equipment. Half

are on duty at any given time and half are on leave. Employees would typically stay at the

hotel/camp facilities and use local personnel transport. These employees include:

• Eight (or 16 total) supervisors who are paid $600/day. They work one week on and

one week off. They work a ten hour day, but are on standby 24 hours a day.

• 46 (or 92 total) craftsman/spill technicians who are paid $500/day. They work 2

weeks on and two weeks off. They also work a ten hour day, but are on standby 24

hours a day.

• Large cleanup efforts are also supported by trained oil company personnel. These

employees participate in training sessions for several hours every two weeks. The

cost for these personnel is not included in the co-op budget but rather in general oil 

company overhead.

Capital Cost

Equipment includes three types of boats, the skimmers and the booms. The life span for the

boats is 10 years with 100 percent dedication to task.

At present, the river boats are 24-foot outboards, but the company that produced these boats is

out of business. In addition, these boats are less environmentally sound than boats with inboard

engines. They will be replaced by new boats with inboard engines. The current 24-foot jet boats 

cost $15,000 each delivered to the North Slope. Also required was a trailer for each boat at

$3,500 per trailer. The boats were built in the in Anchorage and the trailers in the U.S. The

equipment is delivered by truck (2 boats per truck). The boats use a 200 hp Yamaha jet outboard 

engine that cost $12,000. They are Japanese made and are purchased from a local dealer

anchorage dealer at an approximate overhead rate or markup of 30 percent. 

The new river boats, which will be used in the development of the estimates, are 22-foot Silver 

Streak boats with 360 hp inboard jetboat engines. They have stainless steel pumps, are safer and 

more stable, and are more environmentally friendly. They cost $35,000 each. New trailers will

be required at $3,500 each. The old boats will be replaced within five years. The engines are
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Chevrolet factory machine engines that have a base price of $5,200, but cost up to $10,000 with

marine setup.

The two ocean-going 42-foot boats were purchased at a price of $150,000 each. Equipping the

vessel for the North Slope costs an additional $50,000 per boat. This included purchase prices

and installation for navigational equipment, radar, insulation, and heaters.

The skimmer/separators cost $100,000 each including accessories, pumps, motors, controls. 

Two inventors in Keni designed them and custom build them. Each section of river to be

protected requires four skimmers and the four ocean-going and air boats each carry one skimmer. 

Assuming four river protection sites results in an estimate of 20 booms. For transport from

Southern Alaska, all the skimmers would fit on one truck.

Each section of river to be protected requires eight sets of booms with each set assumed to be

200 feet long for a total of 1,600 feet for each river protection site. Assuming four river 

protection sites results in an estimate of 6,400 feet for river protection. Each ocean-going boat

carries 2,000 to 4,000 feet of boom each. Using an assumed average of 3,000 feet for the two

ocean-going boats and an average of 1,000 feet for each of the air boats, results in an estimate of 

8,000 feet of booms for these types of protection and 14,400 feet of boom in total.

The most common spill containment boom used on the North Slope is called 8 by 12 Contractor 

Boom. It has 8" floats and a 12" skirt and is used offshore. The boom comes in 100 foot lengths 

and costs about $13 per foot wholesale at Anchorage. A bundled 100 foot roll weighs 170

pounds and makes a bundle approximately 40" wide by 30" high by 7.5 feet long. The 14,400

feet of boom to serve the co-op will cost $187,200. This includes wholesale margins but no

transportation to the slope.

Fuel Consumption

The out-board river boats consume 18 gallons of fuel per hour and a typical run is about six

hours. The boats are estimated to be used two times per week on average for about four months. 

 Multiplying 17 weeks (34 trips), 18 gallons per hour and six hours per trip, and eight boats,

results in an estimate of 29,376 gallons per year.

The new river boats consume 11 gallons per hour. Assuming the same typical runs as for the old 

river boats, results in an estimate of 17,952 gallons of fuel.

The ocean-going boats consume 13 to 17 gallons per hour. Assuming the same typical runs as

for the river boats, results in an estimate of 6,120 gallons of fuel.

The air boats consume 20 gallons per hour as air powered boats are less efficient. Assuming the 

same typical runs as for the other boats, results in an estimate of 8,160 gallons of fuel.
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4.17 FACILITY ABANDONMENT

The manpower and input vector estimates were developed for abandonment of a production

island. The estimates do not include the costs for abandonment of any of the onshore facilities as 

it is assumed that these facilities would be used for other production projects. 

In reality, abandonment can range from complete removal to a shut down mode with most

facilities left intact for future use. Decisions as to the desired course of action will normally be

decided when the field is abandoned, because of potential unknown future uses. Possible uses of 

an island structure include other oil and gas projects, a deepwater port facility, scientific research 

projects, or a shelter for travelers. A mobile production structure could be relocated for use at

another reservoir. Pipelines are likely to be reused only if production continues, or to supply fuel 

for activities or housing. Housing facilities on an island may be of interest to local government,

businesses, or individuals.

If no uses for facilities can be identified, structures may be removed. Removal involves similar

activities to construction. Mobile production structures are easiest to remove, with islands and

pipelines the most difficult. Some facilities, such as underground offshore pipelines, could be

abandoned in place.

For this study, it is assumed that abandonment in place will be the chosen alternative. The

production island will have most of the modules and equipment removed, but the island itself

will be left intact for possible future uses. All or part of the personnel quarter’s module will be 

left for shelter. The cost of removal is estimated to be similar to the cost of module installation

including transportation. Therefore, the manpower and other costs of this portion of the activity

were estimated using the vector developed for equipping the production island, with the

exception that the costs of the modules and other equipment were not included. A further

description of the development of this data is provided in the Equip Island activity.

It is also assumed that wells will be abandoned. This activity will take four to five days and

consist of removing the first thousand feet of casing and tubing and plugging the well. The time, 

equipment and materials required will be very similar to a well workover. Therefore the costs of 

the well workover activity were used to estimate the cost of well abandonment.

The input vector for a single well abandonment was multiplied by an estimate of the number of

wells per Production Island. The Northstar Island is designed to hold up to 27 wells. The E&D 

scenario for Sale 170 assumes 28 to 29 wells per island depending on the scenario. The E&D

scenario for the Beaufort Sea Sale 144 assumes 30 to 34 wells per island depending on the

scenario. Based on these data, it is assumed 30 wells per island are abandoned.

Remaining facilities are assumed to be abandoned in place. Offshore pipelines which are already 

buried under the sea floor are assumed to be left in place. Onshore pipelines are assumed to left 

for future uses as are hotel/camps and land base operations facilities.
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The manpower estimates and input vectors for island abandonment are the sum of the vectors for 

thirty well workovers and the equipping of a production island (less the actual costs of the 

equipment itself).
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5. LABOR INPUTS

The purpose of this chapter is to provide an overview of the methods used to develop the labor

inputs to the various activities that comprise the oil exploration, development and production

process in the Alaskan Beaufort Sea. Subsequent chapters provide similar discussions for

purchased services, materials, equipment and government. In some sense, this study developed a 

production function for each activity, where the production function is defined in terms of

expenditures for various types of inputs. These inputs can be broadly grouped into the following

categories: labor, purchased services, capital, and materials with the latter including raw,

intermediate and energy material and inputs.

The data developed in this study were based on information collected in the years 1999 and 2000 

and published reports providing data for various years, but mostly for the years 1997 to 1999. 

As such, the estimates provided in this study should be considered to be reported in 1999 dollars.

The model developed in this study is designed to be stimulated by activity levels contained in the 

MMS E&D scenarios. These activity levels then activate input vectors for each activity. This

chapter and those that follow describe the general methods used to develop the expenditure

estimates for each of the major input categories. This chapter provides an overview of the

techniques used to develop later inputs as well as describing some common data and data

development techniques used in the following chapters.

5.1 OVERVIEW OF THE METHODOGY

Labor inputs include the direct labor used in the construction and operation of the oil and gas

facilities as well the overhead or headquarter salaried non-production staff that provide support

functions over a range of operations. As a result, estimates of labor inputs not only considered

employment in the field, but also local and regional offices and headquarters. In order to allow

stimulation of both RAM and IMPLAN, estimates are made for both the man-days of

employment and employee compensation, respectively. The information on man-days is also

used in estimating lodging and food costs. In addition, the development of estimates both in

man-days and employee compensation will facilitate updating of the data in future studies

In calculating estimates of economic impact in cases where workers are commuting, it is

necessary to consider both where the employee works and where the employee spends their

income and pays their taxes. Therefore, while data is initially developed based on the location of 

the workplace of the individual, these estimates are then converted to estimates of the location in 

which the expenditures of wages and payment of taxes are made.
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5.2 ESTIMATES OF PRODUCTION EMPLOYMENT AND WAGES

The first step was to estimate the actual labor used in the field. These direct construction labor

inputs were estimated through interviews with representatives of construction contractors and oil 

companies that have experience in constructing or operating the structures under consideration. 

These estimates are often the most clearly defined, since the work efforts of these types of

employees are most easily assignable to a particular activity. These estimates, which were

developed separately for each individual activity, are discussed in detail in the previous chapter. 

In most cases, data was collected, by activity, on the number of employees by trade, wages for

employees by trade, task crew size, duration of task, number of shifts, shift duration and rotation 

pattern.

These data were tabulated and are presented in Exhibit 5-1. For each activity, the crew members 

are listed by trade. For hourly employees, the wage rate is recorded along with the hours worked 

per day and days per week to calculate a weekly wage. For salaried employees the hourly wage 

is found based on hours per day, days per week, and rotation pattern. Weekly wages are

converted to total wages based on crew sizes, shift factors, number of crews, rotation patterns

and the length of the activity in weeks. Note that for some activities this is simplified as all the

crew members work the same schedule, while for other tasks these calculations must be made at 

the crew member level.

The following paragraphs provide an overview of the data development for each of the activities. 

The section concludes with a discussion of fringe benefits.

Seismic Survey

As discussed in the engineering description for this task in the previous chapter, about 100

workers are required for the operation of the survey, six operators with the cat train company,

and around 94 personnel with the survey company. There is only one shift per day, however,

employees commonly work 16-18 hours a day.

The total Native hire for seismic surveys is negligible. Most of the crew works four weeks on

and two weeks off, resulting in about a 30 percent over hire. For the permanent employees

(about half), there is a $7 per hour benefit package. Sixteen to eighteen hours a day is common; 

so a lot of overtime, at time and a half, is paid.

In total, it is estimated that it would require 3,000 man-days of labor to conduct one month of

seismic survey work based on a 100 person crew for 30 days.
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The first step in compiling this data was to convert all wages to a daily wage. For hourly

employees, the following procedure was used. First, assuming a 16-hour day on average, hourly

employees would work 112 hours a week, and with 72 of those hours at overtime pay, would be 

paid the equivalent of 148 hours a week. Therefore, the hourly wage was multiplied by 148 to

convert to a weekly wage and then divided by seven to convert to a daily wage. For monthly

employees, monthly wages were first divided by 20 to account for the fact that with a four weeks 

on/two weeks off rotation, these employees work 20 days per month on average.

North Slope Support

A resident staff of 20 is required to operate a 300 person hotel/camp. However, total

employment is thirty as ten more personnel would normally be on leave (time off). Ninety

percent of the staff is unskilled at a cost of $300 per day. Ten percent is skilled at a cost of $400 

per day. Ninety percent of the staff is Alaska hire with the remaining ten percent drawn from the 

other 49 states. Fifteen percent of the total staff is Native hire. In total, it is estimated that it

would require 7300 man-days of labor to operate the hotel/camp on an annual basis.

General Personnel Transport

It is estimated that seven workers are required for the operation of the general personnel

transportation function including four drivers, a two member maintenance crew, and a

dispatcher/supervisor. According to the engineering project staff, personnel of this type would

generally work two weeks on and two weeks off.

No wage information was available from the interviews; however, engineering project staff

estimated that the drivers and maintenance crew would be paid $300 per day. The management

employee, the dispatcher/supervisor, would make about $100 more or $400 per day.

Ice Roads and Ice Islands

A total of 50 men for 21 to 30 days, depending on the weather, work two 12 hour shifts, 24 hours 

per day, until the ice road, the island, or both, are complete. Forty men are operators, four are

supervisors, and six are support fuelers/mechanics. The six support personnel will be used

equally on all tasks in this unit. The supervisors are paid $600 per day, while the operators and

support staff are paid $500 per day. The total Native hire for ice road and island construction

activities is 15 percent with 25 percent residing in the NSB.

In total it is estimated that it would require 710 man-days of labor to construct the 10 miles of ice 

road and 390 man-days of labor to construct the ice island.

Drill Ships and Mobile Exploration Platforms

As discussed in the engineering description for this set of activities, there are a number of vessels 

and support functions required for these activities. Each has a specific crew makeup and size. In 
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each of the tasks involving drill ships and exploration platforms, the vessels and support crews in 

use were assumed to vary based on the requirements of the activity. Exhibit 5-1 provides a 

listing of the vessels and support activities employed in each activity and the crews that are 

required for each. In most cases, the crews are identical regardless of the activity. An exception 

is for the drill ship crew itself, which is assumed to be greatly reduced in calm water activities.

Helicopter Support

About five workers are required for the operation of the helicopter support function including 

two pilots, a full time hanger manager and a two member maintenance crew. There is only one

shift per day; however, employees are on call 24 hours a day. It is further assumed that the

helicopter company, headquartered in Anchorage will have overhead type staffing requirements

including individuals from the CEO to the mail room clerk. No information was available on the 

quantity or cost of these overhead employees per helicopter. 

As discussed in the engineering description for this task, the helicopter pilots are paid $500 per

day each. No wage information was provided for the other employees; however, engineering

project staff estimated that each of the two member maintenance crew would be paid $500, the

same as the pilot. The management employee, the hanger manager, would make about $100

more or $600 per day.

Barge Support

Approximately four workers are required for the operation of the barge including a captain, a

ship engineer and two laborers. There is only one shift per day, however, employees commonly 

work as needed and are available 24 hours a day. The total Native hire for the construction is

estimated to be five percent. 

Given the short duration of the task and the fact it takes place in the more desirable summer

months, it is assumed the crew works solid for all four months with no days off. It is further

assumed that one person per barge will be required to fulfill the manager, owner, bookkeeper,

salesperson, dispatcher functions. 

Well Drilling

As discussed in the engineering description for this task, approximately 44 workers are required

for the well drilling operation. These workers are divided among two twelve hour shifts per day. 

 Typically a drilling crew will have two to four percent Natives. In addition, there is one Nativeowned drilling company that uses about 50 percent Native hires. A five percent Native hire for 

the drilling crew was used as an average. The crew works two weeks on and two weeks off.

Assuming a crew size of 44 workers and 90 days to drill an exploration well, the result is an

estimate of 3,960 man-days to drill an exploration well. For production wells with the same size 

crew and an assumed 30 day drilling period, an estimate of 1,320 man-days is derived. For a
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well workover, the 44 person crew and four day drilling period assumptions result in an estimate 

of 176 man-days.

These manpower estimates were then multiplied by estimates of wage rates to develop estimates 

of employment costs. The cost per day for the various field workers involved in the well drilling 

activities was provided in detail in the engineering description of the activity.

Gravel Island Construction

For island construction, which consists of separate activities for gravel placement and island

protection, the number of workers required varies depending on the stage of island construction. 

Typically, an island construction crew will have 5 percent Natives. The crews work two weeks

on and two weeks off. The cost per day for the various field workers involved in the island

construction activities was provided in detail in the engineering description of the activity. 

Production Module Installation

For module installation, the number of workers required varies depending on the task underway. 

For this activity the manpower that was analyzed was limited to the manpower required to

offload, install and hookup the modules. The manpower for the fabrication of the modules in

Anchorage was not included as the modules are treated as purchased goods. As such no

production function for the fabrication of the modules is estimated.

There are assumed to be 50 employees for two weeks for offloading and 120 employees for 120 

days for installation and hookup. Typically, an island construction crew will have 5 percent

Native employees. The crews work two weeks on and two weeks off. 

The cost per day for the various field workers involved in the module installation activities was

provided in detail in the engineering description of the activity.

Production Island Operation

Approximately 31 workers are required per shift for the operation of a production island. 

Typically, a production island operations crew will have 85 percent Alaskan employees with 15

percent Natives. The crews work two weeks on and two weeks off. The cost per day for the

various field workers involved in the operation of the production island were provided in detail

in the engineering description.

Gas Production Facilities

Labor for these facilities was based on scaled down version of the estimates for the production 

facility installation and operation. They were based on a rule of thumb that the facility would

cost roughly one-sixteenth the cost of the full facility.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 127 Arctic IMPAK

Onshore and Offshore Pipelines

As discussed in the engineering description for this task, about 42 workers are required per shift 

for an offshore pipeline construction crew and about 24 for an onshore pipeline construction

crew. Typically a pipeline construction crew will have 5 percent Native employees. The crews 

work four weeks on and four weeks off. The cost per day for the various field workers involved 

in the pipeline construction activities was provided in detail in the engineering description

provided in the previous chapter.

Subsea Pipelines

Construction of the subsea pipeline requires four sets of crews including one for pipeline

construction itself, one for operation of the tugs and lay barges, one for the dive boats and one

for constructing the concrete shapes. The size and composition of each of these crews is

discussed in the engineering description for this activity and enumerated in detail in Exhibit 5-1.

Land Base Operations

It is estimated that approximately 260 workers will provide warehousing services, vehicle

maintenance and hauling services. Typically, a North Slope crew will have 10 percent Natives. 

The crews work two weeks on and two weeks off. Estimates of production worker wages are

developed by averaging the daily pay rates for the various types of employees.

Spill Contingency

As discussed in the engineering description for this task, a staff of 54 is required to operate the

spill containment co-op. However, total employment is 108 as half the personnel would

normally be on leave (time off). Forty-six (92 total) of the staff are craftsman/technicians at a

cost of $500 per day. Eight (16 total) are supervisors at a cost of $600 per day. Five percent of 

the staff is Native hire.

Abandon Island 

Labor estimates for abandoning a production island were based on the assumption that removing 

the production equipment would entail the same labor as installing the equipment and that 

shutting down each of an assumed 30 wells would require the same time and labor as a well 

workover.

Fringe Benefits

Wages were adjusted to include an estimate of the value of fringe benefits. Data for this purpose 

were taken from the 1997 Census of Mineral Industries. The U.S. Oil and Gas Industry volume

contains data on fringe benefits that were used in the analysis. According to data provided in
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 128 Arctic IMPAK

that publication, fringe benefits not included in payroll amounted to 20.4 percent of take home

wages for U.S. oil and gas industry employees.

Some fragmentary data on fringe benefits were reported in the industry interviews conducted for 

this study, such as the per hour information for seismic surveys discussed in the engineering

description for that activity. However, these data were incomplete and therefore, the Census data 

were believed to be more accurate. Note that although the Census data represent an accurate 

average for the industry as a whole, actual rates may vary among activities.

5.3 ESTIMATES OF NON-PRODUCTION EMPLOYMENT AND WAGES

While data on field or production employees by activity could be estimated directly from

primary sources, estimates of office and headquarters personnel attributable to each activity were 

developed using secondary data sources. These estimates were based on industry-level ratios of 

total to production employees. Note that these employees are not necessarily associated with an 

individual activity, but rather represent an allocation of an overhead type function.

The numbers of headquarters and support staff are estimated based on published Census data on

the ratio of total workers to production workers. Exhibit 5-2 provides these ratios from the 1997 

Census of Mineral Industries for a variety of areas and industries for which data were available. 

Data are also provided on the ratio of total to production employee wages and average payroll

per non-production employee. All data are presented on a NAICS code basis.

Region

NAICS 

Code

Number 

of Total 

Employees

Number of 

Production,

 Development,

 and 

Exploration 

Workers

Ratio: 

Total to 

Production 

Employees

Payroll 

for All 

Employees 

($,1000)

Wages for 

Production, 

Development, 

and Exploration 

Workers 

($,1000)

Ratio: 

Total to 

Production 

Employee 

Wages

Number of 

NonProduction 

Employees

Payroll for 

NonProduction 

Employees 

($,1000)

Average 

Payroll Per 

NonProduction 

Employee 

($,1000)

Alaska 211 2,389 1,715 247,884 173,143

213111 1,023 791 54,802 46,364

213112 5,071 3,782 284,113 231,417

Total 8,483 6,288 1.35 586,799 450,924 1.30 2,195 135,875 61,902

U.S. 211111 100,308 58,289 4,968,722 2,717,588

211112 10,549 8,870 541,593 456,083

213111 53,865 45,219 1,918,086 1,539,296

213112 106,339 80,734 3,628,416 2,821,468

Total 271,061 193,112 1.40 11,056,817 7,534,435 1.47 77,949 3,522,382 45,188

Exhibit 5-2: 1997 Census Data on Non-Production Employment and Payroll

The ratios for the sum of the NAICS codes 21111, 213111 and 213112, which combines

exploration, drilling and extraction, were selected to be used in this study as comparable data 

were available for both Alaska and the U.S. Note that non-production employment within

Alaska is 35 percent of direct production employment, while non-production employment within 

the U.S. is 40 percent of the direct production employment. It was assumed that the difference

between the 35 and 40 percent ratios are due to Alaska-related non-production work located in

other parts of the country, not a difference in the number of employees required to accomplish

equivalent tasks. Therefore, it is estimated that for every 100 production workers on an Alaska
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 129 Arctic IMPAK

OCS project, there would be 35 non-production workers in Alaska and five non-production 

workers in the other 49 states.

Non-production employment within Alaska is then divided between the NSB and the remainder

of Alaska based on data provided by industry sources. Based on these interviews it is estimated 

that 41.2 percent of Alaskan non-production employment related to NSB activities are located in 

the NSB, while the remaining 58.8 percent are located elsewhere in Alaska, primarily in

Anchorage. Note that NSB employment refers to location of employment only and that location 

of residence for the vast majority of workers is outside the NSB primarily in South-Central 

Alaska. This is important because most expenditures of personal income are in South-Central 

Alaska.

Exhibit 5-3 provides the estimates of non-production workers and their wages. The number of

full time equivalent (FTE) production workers is estimated as the product of the task work force 

and task length. The resulting estimates of non-production workers are then derived for Alaska

by applying the 35 percent factor and for the U.S. by applying the five percent factor.

Activity

Total 

Task 

Work 

Force

Total Task 

Length 

(weeks)

Number of 

Production 

Workers 

(FTE)

Number of 

Alaskan NonProduction 

Workers (FTE)

Wages for 

Alaskan NonProduction 

Workers

Fringe 

Benefits 

@20.4% of 

Wages

Alaska NonProduction 

Wages and 

Fringe 

Benefits

Number of 

U.S. NonProduction 

Workers (FTE)

Wages for 

U.S. NonProduction 

Workers

Fringe 

Benefits 

@20.4% of 

Wages

U.S. NonProduction 

Wages and 

Fringe 

Benefits

1. Geological Survey 134 4 11.16 3.9 241,056 49,175 290,232 0.609 27,508 5,612 33,120

2. North Slope Support 30 52 30.00 10.5 648,259 132,245 780,503 1.637 73,976 15,091 89,068

3. General Personnel Transport 14 0 0.04 0.0 831 170 1,001 0.002 95 19 114

4. Construct Ice Road 150 5 14.01 4.9 302,758 61,763 364,521 0.765 34,549 7,048 41,597

5. Construct Ice Island 150 3 9.07 3.2 195,902 39,964 235,866 0.495 22,355 4,561 26,916

6. Move Drll Ship/Bottom Founded Platform 232 1/7 0.64 0.2 13,773 2,810 16,582 0.035 1,572 321 1,892

7. Operate Drill Ship in Calm Waters 50 1/7 0.14 0.0 2,968 606 3,574 0.007 339 69 408

8. Operate Drill Ship in Rough Seas 232 1/7 0.64 0.2 13,773 2,810 16,582 0.035 1,572 321 1,892

9. Operate Mobile Exploration Platform 48 0 0.13 0.0 2,849 581 3,431 0.007 325 66 392

10. Helicopter Support 10 0 0.03 0.0 594 121 715 0.001 68 14 82

11. Barge Support 4 0 0.01 0.0 237 48 286 0.001 27 6 33

12. Drill Exploration Well 88 13 21.76 7.6 470,166 95,914 566,079 1.187 53,653 10,945 64,598

13. Drill Production Well 88 4 7.25 2.5 156,722 31,971 188,693 0.396 17,884 3,648 21,533

14. Well Workover 88 1 0.97 0.3 20,896 4,263 25,159 0.053 2,385 486 2,871

15. Construct Gravel Island 124 9 20.44 7.1 441,671 90,101 531,772 1.115 50,401 10,282 60,683

16. Protect Gravel Island 172 26 85.05 29.7 1,837,920 374,936 2,212,856 4.641 209,735 42,786 252,521

17. Equip Production Island 340 19 125.16 43.7 2,704,639 551,746 3,256,386 6.830 308,641 62,963 371,604

18. Operate Production Island 124 52 124.00 43.3 2,679,469 546,612 3,226,080 6.767 305,769 62,377 368,146

19. Construct Gas Production Facility 88 26 44.00 15.4 950,779 193,959 1,144,738 2.401 108,499 22,134 130,632

20. Operate Gas Production Facility 12 52 12.00 4.2 259,303 52,898 312,201 0.655 29,591 6,036 35,627

21. Construct Offshore Pipeline 126 11 25.96 9.1 560,993 114,443 675,436 1.417 64,018 13,060 77,078

22. Construct Onshore Pipeline 72 11 14.84 5.2 320,567 65,396 385,963 0.810 36,582 7,463 44,044

23. Lay Sea Floor Pipeline 328 5 29.74 10.4 642,560 131,082 773,642 1.623 73,326 14,959 88,285

24. Land Base Operation 520 52 520.00 181.5 11,236,482 2,292,242 13,528,725 28.376 1,282,257 261,580 1,543,837

25. Spill Contingency 108 52 108.30 37.8 2,340,142 477,389 2,817,531 5.910 267,047 54,477 321,524

26. Abandon Production Island 428 17 141.10 49.3 3,048,952 621,986 3,670,939 7.700 347,933 70,978 418,911

Exhibit 5-3: Numbers and Wages of Non-Production Worker Wages by Activity by Geographic Area

The number of non-production FTE are then multiplied by the Alaskan and U.S. wage rates from 

Exhibit 5-2. Fringe benefits are then calculated and added to the total for each area.

5.4 WORKERS BY PLACE OF RESIDENCE

Due to the remote location of many E&D activities in Alaska, a large percentage of the

workforce commutes to the project area. Because the geographic spending patterns of workers 

depends heavily on their primary place of residence, an important first step in estimating worker 

spending by area is to establish the primary place of residence for the components of the

workforce.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 130 Arctic IMPAK

According to expert project staff and based on their interviews with industry, it was determined

that oil and gas industry related workers in existing or new production areas will be primarily

drawn from existing pools of workers throughout Alaska, and the lower 49 states. For projects in 

the Beaufort Sea area, labor will continue to be drawn from the various areas in the current

percentages. These percentages were estimated by project staff and are presented in Exhibit 5-4.

Percentage estimates are presented for Native employment, non-Natives from the rest of Alaska

and other U.S. residents.

Percent 

Native

Percent 

Native 

Residing in 

NSB

Percent 

Residing in 

NSB

Percent 

Residing in 

Other Alaska

Percent 

Residing in 

Other Alaska

Percent 

Residing in 

Other U.S.

Percent 

Residing in 

NSB

Percent 

Residing in 

Other Alaska

Percent 

Residing in 

Other U.S.

1. Geological Survey 0% 25% 0.00% 0.00% 80% 20% 0.00% 80.00% 20.00%

2. North Slope Support 15% 25% 3.75% 11.25% 70% 15% 3.75% 81.25% 15.00%

3. General Personnel Transport 0% 25% 0.00% 0.00% 70% 30% 0.00% 70.00% 30.00%

4. Construct Ice Road 15% 25% 3.75% 11.25% 65% 20% 3.75% 76.25% 20.00%

5. Construct Ice Island 15% 25% 3.75% 11.25% 65% 20% 3.75% 76.25% 20.00%

6. Move Drll Ship/Bottom Founded Platform 5% 25% 1.25% 3.75% 75% 20% 1.25% 78.75% 20.00%

7. Operate Drill Ship in Calm Waters 5% 25% 1.25% 3.75% 75% 20% 1.25% 78.75% 20.00%

8. Operate Drill Ship in Rough Seas 5% 25% 1.25% 3.75% 75% 20% 1.25% 78.75% 20.00%

9. Operate Mobile Exploration Platform 5% 25% 1.25% 3.75% 75% 20% 1.25% 78.75% 20.00%

10. Helicopter Support 0% 25% 0.00% 0.00% 90% 10% 0.00% 90.00% 10.00%

11. Barge Support 5% 25% 1.25% 3.75% 80% 15% 1.25% 83.75% 15.00%

12. Drill Exploration Well 5% 25% 1.25% 3.75% 70% 25% 1.25% 73.75% 25.00%

13. Drill Production Well 5% 25% 1.25% 3.75% 70% 25% 1.25% 73.75% 25.00%

14. Well Workover 5% 25% 1.25% 3.75% 70% 25% 1.25% 73.75% 25.00%

15. Construct Gravel Island 5% 25% 1.25% 3.75% 80% 15% 1.25% 83.75% 15.00%

16. Protect Gravel Island 5% 25% 1.25% 3.75% 80% 15% 1.25% 83.75% 15.00%

17. Equip Production Island 5% 25% 1.25% 3.75% 75% 20% 1.25% 78.75% 20.00%

18. Operate Production Island 5% 25% 1.25% 3.75% 75% 20% 1.25% 78.75% 20.00%

19. Construct Gas Production Facility 5% 25% 1.25% 3.75% 75% 20% 1.25% 78.75% 20.00%

20. Operate Gas Production Facility 5% 25% 1.25% 3.75% 75% 20% 1.25% 78.75% 20.00%

21. Construct Offshore Pipeline 5% 25% 1.25% 3.75% 75% 20% 1.25% 78.75% 20.00%

22. Construct Onshore Pipeline 5% 25% 1.25% 3.75% 75% 20% 1.25% 78.75% 20.00%

23. Lay Sea Floor Pipeline 5% 25% 1.25% 3.75% 75% 20% 1.25% 78.75% 20.00%

24. Land Base Operation 10% 25% 2.50% 7.50% 70% 20% 2.50% 77.50% 20.00%

25. Spill Contingency 5% 25% 1.25% 3.75% 75% 20% 1.25% 78.75% 20.00%

26. Abandon Production Island 5% 25% 1.25% 3.75% 75% 20% 1.25% 78.75% 20.00%

Exhibit 5-4: Percent of Production Employees By Ethnicity, Place of Residence and Activity

Activity

Native Workers Non-Native Workers All Workers

Native employment was estimated based on interviews conducted for the study, primarily with

owners and employees of contractors, combined with the personal experience of expert project

staff members who have worked extensively on the NSB. The estimates were developed by

activity and therefore, the total final estimate of the percent of Native workers will depend upon

the specific amounts of the different technologies required in the scenario under examination. 

Note that these are estimates of the number of individuals of Native-Alaskan descent, regardless 

of where they live while not at work. Expert project staff estimated that, approximately 25

percent of these NSB Natives still live in the NSB. The remaining Natives are assumed to live in 

the rest of Alaska.

Labor percentages in the Hope Basin are more hypothetical due to the lack of actual examples. 

However, it is the opinion of expert project staff, that these projects will also draw labor from the 

existing areas in the same percentages as the Beaufort Sea projects. Native labor, however, will 

be from the local Borough.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 131 Arctic IMPAK

5.5 ESTIMATES OF SPENDING BY GEOGRAPHIC REGION

Where an employee spends his/her income, will depend to a large extent, upon whether they are 

a resident or nonresident of the NSB. As discussed above, most workers in the oil industry on the 

North Slope in and near Prudhoe Bay are not permanent residents of the North Slope. They live 

mostly in South-central Alaska and Fairbanks. Since food, lodging and transportation are part of 

an employee's total compensation package; it is unlikely that nonresidents will spend much of

their disposable income in the NSB. This is especially true given the long hours of work and

minimum amount of time for personal leisure. Study team members with extensive experience

working in the area estimate that perhaps $5 per day is spent at informal convenience stores or

on local crafts brought from their villages by Native oil and gas employees. Since most

employees make in the range of $500 per day, it is assumed that one percent of disposable

income of all employees stationed in the NSB is spent on locally produced goods.

Full time NSB residents, on the other hand, will be inclined to spend relatively more of their 

disposable income in the NSB. The extent of those expenditures in the NSB will depend upon

cultural factors (e.g., subsistence living) and the availability of goods and services. Since there is 

little or no manufacturing in the NSB, the impacts of personal consumption there will be felt

primarily in the retail, wholesale, transportation, and service sectors. As noted above, expert

project staff members have estimated the percent of workers who are Natives and the percent of 

NSB Natives who still live in the NSB. In addition it was estimated that those who still lived in

the NSB spent the majority (80 percent) of their income there, with the remainder spent on the

occasional trip outside the NSB to Anchorage or other destinations. NSB Natives who had left

their Native village were estimated to spend none of their disposable income in the NSB, other

than the one percent spent while working. In addition, it was assumed that all employees in

Alaska spent all of their disposable income within Alaska and that all non-Alaska employees

spent all of their income in the lower 49.

The percentages spent in each area for workers who reside in each area are provided in Exhibit

5-5.

NSB

Other 

Alaska Other U.S.

NSB 80 20 0

Other Alaska 1 99 0

Other U.S. 1 0 99

Place of Spending

Place of Full-Time Residence

Exhibit 5-5: Percent of Spending By Place of Full-Time Residence

In stimulating the PCE vectors in IMPLAN it may, be desirable to modify these vectors to take

into account the atypical expenditure patterns of these employees. For example, in the state
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 132 Arctic IMPAK

model, the food and lodging expenditures of nonresidents can be adjusted downward to avoid

potential double counting of the food and lodging provided as compensation on the NSB.

5.6 ESTIMATES OF TAXES, SAVINGS AND PERSONAL CONSUMPTION

EXPENDITURES (PCE)

Once employees are paid wages, they will pay taxes, save a small part of these wages, and then

spend the rest on goods and services, generating induced impacts. To capture the induced

impacts, the wages will need to be converted into disposable income which can then be used to

stimulate IMPLAN's PCE vectors. Note that wages as defined here include fringe benefits,

which is compatible with IMPLAN PCE definitions and standard I-O model conventions.

For the purposes of this study, disposable wages are calculated by reducing Total Personal

Income by 20.5 percent. Of this, 2 percent reflects savings. This figure was estimated from a

trend analysis of personal income data published in the U.S. Statistical Abstract and compiled by 

the U.S. Bureau of Economic Analysis. Due to the modeling complexities involved and the

speed at which financial capital can move across geographic boundaries, IMPAK currently does 

not provide a way for estimating the regional economic impacts associated with savings. 

However, the amounts devoted to savings, by residence, are provided on the output screens and

can be used along with other resources to develop estimates of such impacts.

The combination of taxes paid to local, state and federal government entities reflects the

remaining 18.5 percent. These payments, captured in the model by multiplying tax rate

parameters by estimates of total personal income, are used to stimulate the government

expenditure vectors (See the "Government" section in 10.3.1 for more details).

As an input into the IMPLAN modeling system, the estimates of PCE can used to estimate the

induced impacts that are generated as North Slope employee spend their earnings. The preferred 

way to estimate such impacts would be to allocate IMPAK's PCE estimates to consumer bundles 

using IMPLAN's PCE data to develop the allocation ratios. The resulting vectors would then be 

used to stimulate the outputs of the associated industries in IMPLAN. Note that IMPLAN

provides PCE vectors for several different income groups. Therefore, it will be up to the analyst 

running the IMPLAN model to allocate disposable income to these income groups, or to assume 

that all employees fall within the same income group.

In addition, the analyst should be aware that IMPAK's PCE estimates reflect where goods are

purchased, not where they are produced. As such, the estimates are different than the business

expenditure estimates, which do indicate not only where a good is produced but also where the

associated margins accrue. This means that the two types of expenditures will have to be

handled differently when they are input into IMPLAN. With IMPAK's business expenditures,

the user should not use IMPLAN to apply either margins or RPCs to the expenditure inputs. 

However, just the opposite is the case with IMPAK's PCE estimates, which do need to be

converted into margins and further divided into production regions.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 133 Arctic IMPAK

In some cases it seems as if we have already allocated PCE to consumer bundles since some of

impacted sectors in IMPAK are "consumer oriented". This is only an appearance and is due to

the fact that several activities (e.g., seismic surveys, production operations, and camp support)

involve house-keeping operations that make purchases similar to those conducted by households. 

 Like all other industry impacts reported on the output screens, these impacts are still direct

impacts and will generate indirect impacts if used to stimulate IMPLAN.

5.7 FINAL ESTIMATES OF SPENDING BY AREA

In order to develop the final estimates of spending by area, estimates of wages by production and 

non-production workers are combined and then place of residence and place of spending

percentages are applied and the results summed. In addition, in converting from wages to

spending, wages are reduced to account for taxes and savings, as discussed in the previous

section. The resulting final estimates are provided in Exhibit 5-6.

Exhibit 5-6: Spending by All Workers by Area

NSB

Other 

Alaska

Other 

U.S. NSB

Other 

Alaska

Other 

U.S. Alaska

Other 

U.S. NSB Other Alaska

1. Geological Survey 659,695 0.00% 80.00% 20.00% - 527,756 131,939 290,232 33,120 41.2% 58.8%

2. North Slope Support 2,717,187 3.75% 81.25% 15.00% 101,895 2,207,715 407,578 780,503 89,068 41.2% 58.8%

3. General Personnel Transport 2,649 0.00% 70.00% 30.00% - 1,854 795 1,001 114 41.2% 58.8%

4. Construct Ice Road 435,607 3.75% 76.25% 20.00% 16,335 332,150 87,121 364,521 41,597 41.2% 58.8%

5. Construct Ice Island 240,078 3.75% 76.25% 20.00% 9,003 183,059 48,016 235,866 26,916 41.2% 58.8%

6. Move Drll Ship/Bottom Founded Platform 78,573 1.25% 78.75% 20.00% 982 61,876 15,715 16,582 1,892 41.2% 58.8%

7. Operate Drill Ship in Calm Waters 16,760 1.25% 78.75% 20.00% 209 13,198 3,352 3,574 408 41.2% 58.8%

8. Operate Drill Ship in Rough Seas 78,573 1.25% 78.75% 20.00% 982 61,876 15,715 16,582 1,892 41.2% 58.8%

9. Operate Mobile Exploration Platform 16,158 1.25% 78.75% 20.00% 202 12,724 3,232 3,431 392 41.2% 58.8%

10. Helicopter Support 3,130 0.00% 90.00% 10.00% - 2,817 313 715 82 41.2% 58.8%

11. Barge Support 1,686 1.25% 83.75% 15.00% 21 1,412 253 286 33 41.2% 58.8%

12. Drill Exploration Well 2,581,135 1.25% 73.75% 25.00% 32,264 1,903,587 645,284 566,079 64,598 41.2% 58.8%

13. Drill Production Well 860,378 1.25% 73.75% 25.00% 10,755 634,529 215,095 188,693 21,533 41.2% 58.8%

14. Well Workover 114,717 1.25% 73.75% 25.00% 1,434 84,604 28,679 25,159 2,871 41.2% 58.8%

15. Construct Gravel Island 2,277,005 1.25% 83.75% 15.00% 28,463 1,906,992 341,551 531,772 60,683 41.2% 58.8%

16. Protect Gravel Island 4,503,442 1.25% 83.75% 15.00% 56,293 3,771,632 675,516 2,212,856 252,521 41.2% 58.8%

17. Equip Production Island 9,116,014 1.25% 78.75% 20.00% 113,950 7,178,861 1,823,203 3,256,386 371,604 41.2% 58.8%

18. Operate Production Island 13,007,438 1.25% 78.75% 20.00% 162,593 10,243,357 2,601,488 3,226,080 368,146 41.2% 58.8%

19. Construct Gas Production Facility 5,429,992 1.25% 78.75% 20.00% 67,875 4,276,119 1,085,998 1,144,738 130,632 41.2% 58.8%

20. Operate Gas Production Facility 1,051,814 1.25% 78.75% 20.00% 13,148 828,304 210,363 312,201 35,627 41.2% 58.8%

21. Construct Offshore Pipeline 3,874,773 1.25% 78.75% 20.00% 48,435 3,051,384 774,955 675,436 77,078 41.2% 58.8%

22. Construct Onshore Pipeline 2,249,373 1.25% 78.75% 20.00% 28,117 1,771,381 449,875 385,963 44,044 41.2% 58.8%

23. Lay Sea Floor Pipeline 6,394,829 1.25% 78.75% 20.00% 79,935 5,035,928 1,278,966 773,642 88,285 41.2% 58.8%

24. Land Base Operation 57,954,973 2.50% 77.50% 20.00% 1,448,874 44,915,104 11,590,995 13,528,725 1,543,837 41.2% 58.8%

25. Spill Contingency 12,216,988 1.25% 78.75% 20.00% 152,712 9,620,878 2,443,398 2,817,531 321,524 41.2% 58.8%

26. Abandon Production Island 12,557,527 1.25% 78.75% 20.00% 156,969 9,889,053 2,511,505 3,670,939 418,911 41.2% 58.8%

Activity

Production Employee 

Residence Percentage

Production Wages by Place of 

Residence

Production 

Wages

Non-Production Wages

Alaskan Non-Production 

Employee Residence 

Percentage
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 134 Arctic IMPAK

Exhibit 5-6 (Cont.): Spending by All Workers by Area

NSB

Other 

Alaska

Other 

U.S. NSB

Other 

Alaska

Other 

U.S. NSB

Other 

Alaska

Other 

U.S.

1. Geological Survey 119,576 170,656 33,120 119,576 698,413 165,059 82,915 568,698 129,910

2. North Slope Support 321,567 458,936 89,068 423,462 2,666,651 496,646 294,470 2,166,118 390,885

3. General Personnel Transport 412 588 114 412 2,443 909 289 1,988 715

4. Construct Ice Road 150,183 214,338 41,597 166,518 546,489 128,719 111,273 456,590 101,308

5. Construct Ice Island 97,177 138,689 26,916 106,180 321,749 74,932 70,684 270,115 58,975

6. Move Drll Ship/Bottom Founded Platform 6,832 9,750 1,892 7,814 71,627 17,607 5,679 57,616 13,857

7. Operate Drill Ship in Calm Waters 1,472 2,101 408 1,682 15,300 3,760 1,221 12,309 2,959

8. Operate Drill Ship in Rough Seas 6,832 9,750 1,892 7,814 71,627 17,607 5,679 57,616 13,857

9. Operate Mobile Exploration Platform 1,413 2,017 392 1,615 14,741 3,623 1,173 11,859 2,852

10. Helicopter Support 294 420 82 294 3,238 395 216 2,595 311

11. Barge Support 118 168 33 139 1,580 285 103 1,265 225

12. Drill Exploration Well 233,225 332,855 64,598 265,489 2,236,442 709,882 192,274 1,802,404 558,713

13. Drill Production Well 77,742 110,952 21,533 88,496 745,481 236,627 64,091 600,801 186,238

14. Well Workover 10,366 14,794 2,871 11,800 99,397 31,550 8,546 80,107 24,832

15. Construct Gravel Island 219,090 312,682 60,683 247,552 2,219,673 402,234 178,288 1,786,355 316,578

16. Protect Gravel Island 911,697 1,301,159 252,521 967,990 5,072,791 928,037 663,348 4,146,451 730,412

17. Equip Production Island 1,341,631 1,914,755 371,604 1,455,581 9,093,616 2,194,807 1,015,493 7,388,568 1,727,423

18. Operate Production Island 1,329,145 1,896,935 368,146 1,491,738 12,140,293 2,969,633 1,068,869 9,792,204 2,337,250

19. Construct Gas Production Facility 471,632 673,106 130,632 539,507 4,949,225 1,216,631 392,145 3,981,069 957,549

20. Operate Gas Production Facility 128,627 183,574 35,627 141,775 1,011,878 245,990 100,169 818,941 193,606

21. Construct Offshore Pipeline 278,279 397,156 77,078 326,714 3,448,540 852,032 241,980 2,766,121 670,592

22. Construct Onshore Pipeline 159,017 226,946 44,044 187,134 1,998,328 493,919 138,831 1,602,538 388,739

23. Lay Sea Floor Pipeline 318,740 454,901 88,285 398,676 5,490,829 1,367,250 308,080 4,384,947 1,076,094

24. Land Base Operation 5,573,835 7,954,890 1,543,837 7,022,709 52,869,994 13,134,832 4,991,181 42,727,940 10,337,770

25. Spill Contingency 1,160,823 1,656,708 321,524 1,313,535 11,277,586 2,764,922 947,046 9,084,877 2,176,132

26. Abandon Production Island 1,512,427 2,158,512 418,911 1,669,396 12,047,565 2,930,417 1,180,811 9,747,470 2,306,384

Total Wages by Place of Residence Spending by Area

Activity

Non-Production Wages by Place of 

Residence

In the exhibit production worker wages including fringe benefits are transcribed from Exhibit 5-1 

and distributed to place of residence based on percentages from Exhibit 5-4. Non-production 

wages, which were already distributed by place of residence, are taken from Exhibit 5-3. 

Production and non-production worker wages are then summed to provide total wages by place

of residence. These wages are then converted to spending by area based on the percentages from 

Exhibit 5-5 and the estimate of the percent diverted to taxes and savings. Taxes and savings are 

directly calculated in the model by applying the tax and savings percentages to the estimates of

total wages by place of residence.

5.8 OTHER EMPLOYEE RELATED COSTS

In addition to direct compensation, several contractors provided estimates of additional employee 

related costs for airfare to and from the NSB, local transportation, clothing, and housing and

meal costs. While these costs are theoretically not part of employee compensation, but rather

part of overhead costs, their levels are dependent upon the numbers and of employees and are

therefore most accurately estimated along with employee compensation. They are assumed to

not be included in Bureau of the Census’ estimates of fringe benefits and are coded directly to

the appropriate IMPLAN sectors, or used to stimulate secondary activities

Interviews with several contractors conducted for this study revealed employee related costs of

up to $120 for employees working on the North Slope. Included in the $120 is an estimated $75 

per day for food and lodging, $20 for airfare, $15 for local transportation, and $10 for cold

weather gear and other miscellaneous expenses. These overhead costs are assumed to apply to
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 135 Arctic IMPAK

both regular and supervisory production personnel. In addition, supervisory personnel are

assumed to be provided with office space and a private bath at an extra $35 per day.

Since these estimates apply to employees housed in an on-shore hotel/camp on a four week

rotation, adjustments were required depending on the type of employee and the activity. For

airfares, since the $20 per day for airfare was based on a $550 airfare and a 28 day rotation,

airfare was doubled to $40 per day for employees who are on a two week rotation. For food and 

lodging, employees in certain activities such as production island operation or seismic survey cat 

train are not assumed to live on site rather than at contractor purchased lodging. Instead their

food and lodging is assumed to be company provided and the costs of the quarters and food are

estimated as part of the production function for that activity. For local travel, employees staying 

on site such as is the case with the production island or seismic survey cat train, are not assumed 

to require daily transport. Employees who stay on-site are generally assumed to require only one 

day of local travel per two week shift (one trip out to the island, platform or mobile structure and 

one trip back). To reflect this fact, local transportation is reduced to approximately $1 per day. 

Cat-train employees are assumed to require no local travel.

The following paragraphs summarize the allocations of these costs to each sector in more detail.

The estimates of other employee related costs by activity, type of cost are provided in Exhibit 5-

7. 
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 136 Arctic IMPAK

1. Geological Survey Cat-Train 0% 100% 0% 4/6 1/28 7 387 2,707 4.5% 870

2. North Slope Support Camp 0% 0% 0% 4/6 1/28 7 1,040 7,280 10.0% 2,340

3. General Personnel Transport Camp 100% 100% 0% 2/4 1/14 7 1.0 7 14.3% 2

4. Construct Ice Road Camp 100% 100% 100% 2/4 1/14 7 101 710 9.6% 228

5. Construct Ice Island Camp 100% 100% 100% 2/4 1/14 7 56 390 11.3% 125

6. Move Drll Ship/Bottom Founded Platform Platform 0% 100% 0% 2/4 1/14 7 17 116 6.9% 37

7. Operate Drill Ship in Calm Waters Ship 0% 100% 0% 2/4 1/14 7 4 25 12.0% 8

8. Operate Drill Ship in Rough Seas Ship 0% 100% 0% 2/4 1/14 7 17 116 6.9% 37

9. Operate Mobile Exploration Platform Platform 0% 100% 0% 2/4 1/14 7 27 190 1.6% 61

10. Helicopter Support Camp 100% 100% 100% 2/4 1/14 7 0.7 5 20.0% 2

11. Barge Support Camp 100% 100% 100% 16/16 1/112 7 0.6 4 25.0% 1

12. Drill Exploration Well Camp 100% 100% 100% 2/4 1/14 7 566 3,960 4.5% 1,273

13. Drill Production Well Camp 100% 100% 100% 2/4 1/14 7 189 1,320 4.5% 424

14. Well Workover Island 0% 100% 7% 2/4 1/14 7 25 176 4.5% 57

15. Construct Gravel Island Camp 100% 100% 100% 2/4 1/14 7 531 3,720 9.7% 1,195

16. Protect Gravel Island Camp 100% 100% 100% 2/4 1/14 7 1,063 7,440 8.1% 2,391

17. Equip Production Island Camp 100% 100% 100% 2/4 1/14 7 2,157 15,100 6.7% 4,853

18. Operate Production Island Island 0% 100% 7% 2/4 1/14 7 3,224 22,568 6.5% 7,252

19. Construct Gas Production Facility Camp 100% 100% 100% 2/4 1/14 7 1,144 8,008 6.8% 2,573

20. Operate Gas Production Facility Camp 100% 100% 100% 2/4 1/14 7 312 2,184 33.3% 702

21. Construct Offshore Pipeline Camp 100% 100% 100% 4/6 1/28 7 900 6,300 9.5% 2,025

22. Construct Onshore Pipeline Camp 100% 100% 100% 4/6 1/28 7 514 3,600 16.7% 1,157

23. Lay Sea Floor Pipeline Camp 100% 100% 100% 2/4 1/14 7 1436.6 10,056 9.3% 3,232

24. Land Base Operation Camp 100% 50% 100% 2/4 1/14 7 13,520 94,640 12.3% 30,414

25. Spill Contingency Camp 100% 100% 100% 2/4 1/14 7 2,816 19,710 14.8% 6,334

26. Abandon Production Island Camp 100% 100% 100% 2/4 1/14 7 2,911 20,380 6.2% 6,549

Activity

Production 

Worker 

Percent 

Supervisor

NonProduction 

Worker ManDays

Exhibit 5-7: Production Worker Lodging Expenses

Production 

Worker

 Man-Weeks

Days/

Week

Place of 

Residence 

for

Employees

Work Clothes 

Percentage

Daily Air 

Travel 

Cost

Hotel/Camp 

Percentage

Local Travel 

Percentage

Production 

Worker ManDays

Rotation 

Pattern: 

Weeks 

On/Total 

Weeks

1. Geological Survey - - 69,596 69,596 26,098 27,071 - 87,351

2. North Slope Support - - 187,160 187,160 70,185 - - 234,909

3. General Personnel Transport 270 80 180 530 277 70 - 363

4. Construct Ice Road 28,890 5,440 18,253 52,583 28,145 7,100 10,650 36,857

5. Construct Ice Island 15,570 3,520 10,026 29,116 15,460 3,900 5,850 20,245

6. Move Drll Ship/Bottom Founded Platform - - 2,982 2,982 1,118 1,160 - 6,022

7. Operate Drill Ship in Calm Waters - - 643 643 241 250 - 1,298

8. Operate Drill Ship in Rough Seas - - 2,982 2,982 1,118 1,160 - 6,022

9. Operate Mobile Exploration Platform - - 4,885 4,885 1,832 1,900 - 9,863

10. Helicopter Support 180 80 129 389 198 50 75 260

11. Barge Support 135 80 103 318 159 40 60 70

12. Drill Exploration Well 170,100 14,400 101,807 286,307 156,978 39,600 59,400 205,566

13. Drill Production Well 56,700 4,800 33,936 95,436 52,326 13,200 19,800 68,522

14. Well Workover - - 4,525 4,525 1,697 1,760 189 9,136

15. Construct Gravel Island 151,200 28,800 95,637 275,637 147,464 37,200 55,800 193,107

16. Protect Gravel Island 307,800 48,000 191,273 547,073 294,928 74,400 111,600 386,215

17. Equip Production Island 633,780 81,280 388,203 1,103,263 598,576 151,000 226,500 783,850

18. Operate Production Island - - 580,196 580,196 217,574 225,680 24,180 1,171,518

19. Construct Gas Production Facility 335,790 43,680 205,876 585,346 317,444 80,080 120,120 415,700

20. Operate Gas Production Facility 65,520 58,240 56,148 179,908 86,576 21,840 32,760 113,373

21. Construct Offshore Pipeline 256,500 48,000 161,965 466,465 249,737 63,000 94,500 203,287

22. Construct Onshore Pipeline 135,000 48,000 92,552 275,552 142,707 36,000 54,000 116,164

23. Lay Sea Floor Pipeline 410,310 75,040 258,528 743,878 398,628 100,560 150,840 522,013

24. Land Base Operation 3,734,640 931,840 2,433,081 7,099,561 3,751,605 473,200 1,419,600 4,912,816

25. Spill Contingency 755,550 233,600 506,720 1,495,870 781,320 197,100 295,650 1,023,157

26. Abandon Production Island 860,580 100,480 523,945 1,485,005 807,880 203,800 305,700 1,057,937

Work Clothing 

@$10/day

Local Travel 

@$15/day

Air Travel @$550 

Per Round Trip

Food Service 

@$30/day

Production NonSupervisor 

Worker Lodging 

@$45/day

Non- Production 

Worker Lodging 

@$80/day

Total Lodging 

Cost

Production 

Supervisor 

Worker Lodging 

Activity @$80/day

Seismic survey production employees were assumed to receive food and lodging in the cat train

camp and as they are away from camp do not require local travel. Therefore only air travel and

work gear were assigned to these employees. Since these employees work for four weeks at a

time, they require only a twenty-eighth of an airfare per day.

The hotel/camp employees were assumed to be provided room and board at no cost, require 

minimal ground transport and none of the specialized outdoor work gear. Since these employees 

work for four weeks at a time, they require only a twenty-eighth of an airfare per day.

General personnel transport employees were assumed to stay at the hotel/camp. The $15 for

local transportation was assumed to not apply to these employees, as they work in this sector. 
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 137 Arctic IMPAK

Employees working in ice roads and islands were assumed to stay at hotel camps and require

work clothes and daily ground transport.

Employees involved with drill ships and mobile platforms were assumed to stay onboard ship

and as such do not require use of the hotel camp or daily ground transport.

Helicopter employees were assumed to stay at hotel/camps and require clothing and ground 

transport.

Barge workers were assumed to stay at the hotel/camps and to use local transport. However,

they only require one round-trip air flight per year as they work all summer.

Adjustments were made to employee-related costs for well drilling employees based on the type 

of well. Well workover employees were assumed to receive company provided food and lodging 

on the production island and as such these employees were not charged for food and lodging. 

Since these employees stay at the work site, they only require one day of local travel per two

week shift (one trip out to the island and one trip back). All of the employee-related costs were

assumed to apply to exploratory and production well drilling employees as they will stay at the

hotel/camp and commute to the drilling site.

Gravel production island construction employees were assumed to stay at hotel/camps, require a 

fourteenth of an airfare per day as they work a two-week shift, and require daily ground transport

and work clothing.

The workers for production module installation and gas production facility installation were

assumed to stay at hotel/camps, require a fourteenth of an airfare per day as they work a twoweek shift, and require daily ground transport and work clothing.

Employees operating equipment on the production island were assumed to receive company

provided food and lodging on the production island and as such these employees were not

charged for food and lodging. Since these employees stay at the work site, they only require one 

day of local travel per two week shift (one trip out to the island and one trip back).

The workers constructing pipelines were assumed to stay at hotel/camps, require a fourteenth of 

an airfare per day as they work a two-week shift, and require daily ground transport and work

clothing.

Land base operation employees were assumed to stay at hotel/camps, require a fourteenth of an

airfare per day as they work a two-week shift, and require daily ground transport. However,

since approximately half work indoors in warehouses, on average they are assumed to require

only 50 percent of the cost for the specialized cold weather work clothing.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 138 Arctic IMPAK

The spill contingency workers were assumed to stay at hotel/camps, require a fourteenth of an

airfare per day as they work a two-week shift, and require daily ground transport and work

clothing.

Finally, North Slope salaried employees were assumed to receive the same food, lodging and

airfare as the supervisory production employees. They were not assigned costs for local travel

and work gear.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 139 Arctic IMPAK

6. PURCHASED SERVICES INPUTS

Purchases from service sectors represent overhead types of costs that are usually not separately

specified in the type of engineering cost estimates used in this study. If they are considered, they 

are generally lumped together in a common overhead category. Moreover, while these purchases 

are part of the real costs of doing business, no data is available to directly allocate them to the

different activities. Part of the problem is that these costs represent common overhead

components. The amount of advertising that is purchased by a large oil company, for example,

is probably fairly independent of the miles of pipelines constructed, but is probably somewhat

related to gallons of oil produced. On the other hand, a smaller company specializing in pipeline 

construction, although likely to have a small advertising budget, is likely to have spending fairly

related to the miles of pipelines it constructs in a year.

The assignment of these costs by area is also problematic. The oil and gas industry is an

amalgamation of a large number of companies, not just the big oil companies. For example, the

1992 Census of Mineral Industries estimates that almost 17,000 companies were involved in the 

Crude Petroleum and Natural Gas and Oil and Gas Field Services industries. Therefore, one can 

not simply ask the large oil companies where they spend their overhead dollar, even assuming

they would be willing to provide an answer. Instead, estimates must be made of where the

aggregate of all companies make their expenditures.

6.1 NATIONAL INPUT/OUTPUT DATA

As discussed above, most major inputs to the IMPAK model were estimated based on

information on cost and quantity gathered in the industry interviews or based on the expert

engineering knowledge of project staff. However, in order to determine what purchased services 

are utilized in quantities that are significant enough to warrant estimation, data from the latest

national-level input-output table of the U.S. economy were tabulated and analyzed. The latest

table available is for the year 1992, as developed by the Bureau of Economic Analysis, and

published in September 1998. Data from this table is tabulated and presented in Exhibits 6-1 and 

6-2.

As shown in Exhibit 6-1, the various activities that comprise the oil and gas industry are

subsumed within four sectors in the national I-O table. The largest of these sectors is mining

Sector 8.0001, Crude Petroleum and Natural Gas. The three smaller sectors are all construction

industries. These include Sector 11.0601 (Petroleum and Natural Gas Well Drilling), Sector

11.0602 (Petroleum, Natural Gas, and Solid Mineral Exploration), and Sector 12.0215

(Maintenance and Repair of Petroleum and Natural Gas Wells).
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 140 Arctic IMPAK

BEA #11.0601 BEA #11.0602 BEA #12.0215

BEA #8.0001 Construction: Construction: Construction:

Mining: Petroleum Petroleum, Maintenance

Crude and Natural and Repair

Petroleum Natural Gas, and of Petroleum

BEA I-O and Gas Solid and

Industry Natural Well Mineral Natural

Number BEA I-O Industry Name Gas Drilling Exploration Gas Wells

MAJOR INTERMEDIATE INPUTS

27.0100 Industrial inorganic and organic chemicals 853 394 7 25

27.0406 Chemicals and chemical preparations, n.e.c. 321 62 1 4

29.0203 Polishes and sanitation goods 5 0 0 27

31.0101 Petroleum refining 386 254 25 14

31.0102 Lubricating oils and greases 244 81 1 0

31.0200 Asphalt paving mixtures and blocks 0 0 0 23

36.0100 Cement, hydraulic 187 88 0 33

36.1100 Concrete products, except block and brick 0 0 0 14

36.1900 Minerals, ground or treated 0 108 0 3

37.0101 Blast furnaces and steel mills 1079 221 16 21

37.0103 Steel wiredrawing and steel nails and spikes 112 14 1 0

40.0400 Fabricated structural metal 19 138 7 9

42.0800 Pipe, valves, and pipe fittings 434 15 0 24

45.0100 Construction machinery and equipment 200 139 10 0

46.0300 Hoists, cranes, and monorails 0 0 0 16

50.0400 Industrial and commercial machinery and equipment, n.e.c. 157 127 0 0

53.0500 Relays and industrial controls 66 0 0 0

62.0200 Mechanical measuring devices 1 22 7 0

65.0100 Railroads and related services 99 76 0 7

65.0200 Local and suburban transit and interurban highway passenger transportation 61 6 1 1

65.0301 Trucking and courier services, except air 251 101 1 31

65.0400 Water transportation 264 32 0 1

65.0500 Air transportation 246 29 5 6

66.0100 Telephone and telegraph communications, and communications sevices, n.e.c. 196 45 11 4

68.0100 Electric services (utilities) 1626 55 12 8

68.0201 Natural gas transportation 2303 0 0 0

68.0202 Natural gas distribution 518 103 10 0

68.0301 Water supply and sewerage systems 82 5 0 0

69.0100 Wholesale trade 935 301 10 40

69.0200 Retail trade, except eating and drinking 126 15 1 1

70.0100 Banking 567 64 9 12

70.0400 Insurance carriers 113 11 3 3

71.0201 Real estate agents, managers, operators, and lessors 521 85 24 11

71.0202 Royalties 16661 5 152 1

72.0101 Hotels 264 30 5 5

73.0103 Personnel supply services 154 18 3 3

73.0104 Computer and data processing 115 16 1 4

73.0111 Management and consulting services 135 17 3 3

73.0200 Advertising 128 25 5 4

73.0301 Legal services 980 93 9 4

73.0302 Engineering, architectural, and surveying services 874 0 0 0

73.0303 Accounting, auditing, and bookeeping, and miscellaneous services, n.e.c. 28 5 0 15

74.0000 Eating and drinking places 312 35 6 7

75.0001 Automotive rental and leasing, without drivers 96 12 1 2

77.0501 Business associations and professional membership organizations 62 6 1 1

Total 31781 2853 348 387

INTRA-INDUSTRY PURCHASES

8.0001 Crude petroleum and natural gas 20296 0 0 0

11.0601 Petroleum and natural gas well drilling 0 107 0 0

11.0602 Petroleum, natural gas and solid mineral exploration 0 0 63 0

12.0215 Maintenance and repair of petroleum and natural gas wells 1719 0 0 0

Total 22015 107 63 0

OTHER COMPONENTS OF OUTPUT

80.0000 Noncomparable imports 1033 0 0 0

88.0000 Compensation of employees 14127 6529 1042 1019

89.0000 Indirect business tax and nontax liability 4729 515 56 37

90.0000 Other value added 30457 1337 143 201

Total 50346 8381 1241 1257

TOTAL OUTPUT 105369 11633 1673 1719

Percentage of all Inputs Accounted for 98.84% 97.49% 98.74% 95.64%

Percentage of all Intermediate Inputs Accounted for 96.28% 90.72% 94.31% 83.77%

Exhibit 6-1: Selected Oil and Gas Industry Input Data From the 1992 BEA National Input-Output Table

(Millions of Dollars)

Exhibit 6-1 provides the dollars of purchases for all input sectors that accounted for at least one

half of one percent of industry output for any of the four sectors. In total, there were 53 sectors
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 141 Arctic IMPAK

that met this criterion. Note that as shown at the bottom of Exhibit 6-1, the purchases from these 

53 sectors account for 96 to 99 percent of the total purchases of the four oil and gas sectors.

BEA # BEA # BEA # BEA #

BEA I-O 65.0200 65.0400 65.0500 72.0101

Industry Local Water Air Hotels

Number BEA I-O Industry Name Transport Transport Transport

MAJOR INTERMEDIATE INPUTS

12.0300 Other maintenance and repair - - - 1,390

19.0200 Housefurnishings, n.e.c. - - - 483

31.0101 Petroleum refining 1,352 727 9,432 -

32.0100 Tires and inner tubes 135 - - -

32.0500 Rubber and plastics hose and belting 103 - - -

42.0800 Pipe, valves, and pipe fittings 151 - - -

43.0200 Internal combustion engines, n.e.c. 191 217 - -

49.0200 Ball and roller bearings 177 184 - -

59.0302 Motor Vehicle parts and accessories 374 - - -

60.0200 Aircraft and missile engines and engine parts - - 1,375 -

60.0400 Aircraft and missile equipment, n.e.c. - - 921 -

61.0100 Ship building and repairing - 585 - -

65.0301 Trucking and courier services, except air 269 - - 279

65.0701 Freight forwarders and other transportation services - 873 734 -

65.0702 Arrangement of passenger transportation - 525 6,967 793

66.0100 Telephone and telegraph communications, and communications sevices, n.e.c. 346 - 1,204 363

66.0200 Cable and other pay television services - - - 369

68.0100 Electric services (utilities) - - - 1,830

68.0202 Natural gas distribution - - - 318

68.0302 Sanitary services, steam supply, and irrigation systems - - - 621

69.0100 Wholesale trade 1,120 505 1,462 402

69.0200 Retail trade, except eating and drinking 162 - - -

70.0100 Banking 169 469 601 1,670

70.0200 Credit agencies other than banks - 526 784 1,335

70.0400 Insurance carriers 158 - - -

71.0201 Real estate agents, managers, operators, and lessors 301 877 1,425 1,353

73.0102 Services to dwellings and other buildings - - - 619

73.0103 Personnel supply services 430 - - 504

73.0104 Computer and data processing - 280 2,224 341

73.0106 Detective and protective services - - - 406

73.0107 Miscellaneous equipment rental and leasing - 186 675 -

73.0109 Other business services - 198 - 941

73.0111 Management and consulting services - 911 - 971

73.0112 Testing and research labs - 743 - -

73.0200 Advertising - 1,244 1,389 974

73.0301 Legal services 189 164 944 289

73.0302 Engineering, architectural, and surveying services - 302 - -

73.0303 Accounting, auditing, and bookeeping, and miscellaneous services, n.e.c. - 217 - -

74.0000 Eating and drinking places - - 1,832 298

75.0001 Automotive rental and leasing, without drivers 325 - - -

78.0100 U.S. Postal Service - - - 264

Total 5,952 9,733 31,969 16,813

INTRA-INDUSTRY PURCHASES

65.0200 Local transportation - - - -

65.0400 Water transportation - 4,282 - -

65.0500 Air transportation - - 6,064 -

72.0101 Hotels - - - -

Total 0 4282 6064 0

OTHER COMPONENTS OF OUTPUT

80.0000 Noncomparable imports - 2,954 8,827 -

88.0000 Compensation of employees 8,704 7,140 32,761 19,934

89.0000 Indirect business tax and nontax liability 169 583 5,696 4,999

90.0000 Other value added 3,515 5,073 3,709 6,159

Total 12388 15750 50993 31092

TOTAL OUTPUT 20166 32440 94141 52407

Percentage of all Inputs Accounted for 90.95% 91.75% 94.57% 91.41%

Percentage of all Intermediate Inputs Accounted for 76.52% 78.44% 86.21% 78.88%

Exhibit 6-2: Selected Miscellaneous Sector Input Data From the 1992 BEA National Input-Output Table

(Millions of Dollars)
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 142 Arctic IMPAK

Many of these sectors were not of interest in the analysis of purchased services and were

therefore dropped from the analysis. These sectors can be classified into six groups. One such

group of sectors is those that represent intra-industry purchases, such as the purchases the Crude 

Petroleum and Natural sector makes from itself and the other three oil and gas sectors listed in

the table.

A second group of sectors includes those that represent other components of output such as

compensation of employees, and non-comparable imports. Estimates for these sectors were

made from primary sources. Non-comparable imports are estimated as foreign purchased

equipment.

A third set of industries that are not important in the analysis of purchased services are those that 

are often referred to as margin industries. In input-output analysis, the value of a purchase is

divided between the amount paid for the actual good and the amount paid others to transport,

wholesale and retail the good. While the values of purchases from these sectors are estimated as 

part of this study, these estimates are derived and subtracted from the estimates made for

purchases of capital and materials.

A fourth set of sectors are selected utility sectors such as electricity, natural gas, and water and

sewer. Since the oil and gas production in Alaska is so isolated, the production process normally 

generates its own power and waste disposal and does not separately purchase these inputs.

A fifth set of industries are those that supply or are related to the capital goods that are

purchased. Capital goods purchases from these sectors are derived from primary data sources

and are discussed in Chapter 7. 

A sixth set of industries are those that provide material inputs. These include the following

sectors:

• 27.0100 Industrial inorganic and organic chemicals

• 27.0406 Chemicals and chemical preparations, n.e.c.

• 29.0203 Polishes and sanitation goods

• 31.0101 Petroleum refining

• 31.0102 Lubricating oils and greases

• 31.0200 Asphalt paving mixtures and blocks

• 36.0100 Cement, hydraulic

• 36.1100 Concrete products, except block and brick

• 36.1900 Minerals, ground or treated

These inputs are also derived from primary sources and are discussed in Chapter 8.

After eliminating these six types of sectors, the 18 sectors that remain are considered to be the

types of sectors supplying the purchased services that are of interest here. These include the

following BEA I-O codes and sectors:
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 143 Arctic IMPAK

• 66.0100 Telephone and telegraph communications, and communications services, n.e.c.

• 70.0100 Banking

• 70.0400 Insurance carriers

• 71.0201 Real estate agents, managers, operators, and lessors

• 71.0202 Royalties

• 72.0101 Hotels

• 73.0103 Personnel supply services

• 73.0104 Computer and data processing

• 73.0111 Management and consulting services

• 73.0200 Advertising

• 73.0301 Legal services

• 73.0302 Engineering, architectural, and surveying services

• 73.0303 Accounting, auditing, and bookkeeping, and miscellaneous services, n.e.c.

• 74.0000 Eating and drinking places

• 75.0001 Automotive rental and leasing, without drivers

• 77.0501 Business associations and professional membership organizations

• 90.0000 Other value added.

The data for the oil and gas industry, provided in Exhibit 6-1 are used for all of the activities

except for camp support, helicopter support and boat support. These activities are secondary

support activities that are not part of the oil and gas industry as traditionally defined by inputoutput models. As a result, purchased services data for these activities were based on the inputoutput data for hotels, air transport, and water transport, respectively. These data are shown in

Exhibit 6-2.

As was the case with the oil and gas input-output sectors, Exhibit 6-2 provides information for

inputs that accounted for at least one half of one percent. The list of included sectors is slightly

different than for Exhibit 6-1. Once again, sectors that were not considered purchased services

were eliminated from consideration.

6.2 THE CALCULATION OF TOTAL PURCHASED SERVICES

The calculation of total overhead or purchased services expenditures is based on the ratio of

these expenditures to labor compensation. The choice of labor compensation is based on the

relative quality of the labor data and the availability of labor data for all of the activities

including the secondary, non oil and gas industry sectors.

Exhibits 6-3 and 6-4 list the purchased services sectors and their ratio to labor compensation

from the national input-output tables. The BEA I-O sector number and name is provided along

with the corresponding IMPLAN sector number. Exhibit 6-3 provides this data for oil and gas

industries, while Exhibit 6-4 provides this data for the hotel, air and water sectors. The ratios
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 144 Arctic IMPAK

provided in these exhibits are multiplied by the total labor compensation for each of the activities 

to generate estimates of purchased services inputs.

NSB Other Alaska Other U.S.

66.0100 Telephone communications 441 1.13 20 60 20

70.0100 Banking 456 2.87 5 60 35

70.0400 Insurance carriers 459 0.57 0 60 40

71.0201 Real estate agents 462 2.82 10 50 40

72.0101 Hotels 463 1.34 5 50 45

73.0103 Personnel supply 474 0.78 15 50 35

73.0104 Computers & data processing 475 0.60 25 40 35

73.0111 Management & consulting 508 0.70 10 50 40

73.0200 Advertising 469 0.71 0 40 60

73.0301 Legal services 494 4.78 0 40 60

73.0302 Engineering, architectural & surveying 506 3.85 15 45 40

73.0303 Accounting, auditing & bookeeping 507 0.21 10 60 30

74.0000 Eating & drinking places 454 1.58 5 50 45

75.0001 Automotive rental & leasing 477 0.49 20 50 30

77.0501 Associations & professional org. 503 0.31 0 40 60

90.0000 Other value added n.a. 70.74 0 20 80

88.0000 Compensation of Employees n.a. n.a. n.a. n.a.

Exhibit 6-3: Percentage Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

Sector Name IMPLAN Sector

Percent of 

Labor 

BEA I-O 

Sector

Percent of Purchased Services

65.0200 

Local 

Transport

65.0400 

Water 

Transport

65.0500 Air 

Transport

72.0101 

Hotels NSB

Other 

Alaska Other U.S.

66.0100 Telephone communications 441 3.98 - 3.68 1.82 20% 60% 20%

66.0200 Cable TV 441 - - - 1.85 20% 60% 20%

70.0100 Banking 456 1.94 6.57 1.83 8.38 5% 60% 35%

70.0200 Credit agencies 457 - 7.37 2.39 6.70 5% 60% 35%

70.0400 Insurance carriers 459 1.82 - - - 0% 60% 40%

71.0201 Real estate agents 462 3.46 12.28 4.35 6.79 10% 50% 40%

73.0102 Services to dwellings/buildings 472 - - - 3.11 10% 60% 30%

73.0103 Personnel supply 474 4.94 - - 2.53 15% 50% 35%

73.0104 Computers & data processing 475 - 3.92 6.79 1.71 25% 40% 35%

73.0106 Detective services 476 - - - 2.04 10% 60% 30%

73.0107 Equipment rental & leasing 473 - 2.61 2.06 - 10% 60% 30%

73.0109 Other business services 470 - 2.77 - 4.72 10% 50% 40%

73.0111 Management & consulting 508 - 12.76 - 4.87 10% 50% 40%

73.0112 Testing and research labs 509 - 10.41 - - 0% 20% 80%

73.0200 Advertising 469 - 17.42 4.24 4.89 0% 40% 60%

73.0301 Legal services 494 2.17 2.30 2.88 1.45 0% 60% 40%

73.0302 Engineering, architectural & surveying 506 - 4.23 - - 15% 45% 40%

73.0303 Accounting, auditing & bookeeping 507 - 3.04 - - 10% 60% 30%

74.0000 Eating & drinking places 454 - - 5.59 1.49 5% 50% 45%

75.0001 Automotive rental & leasing 477 3.73 - - - 20% 50% 30%

78.0100 U.S. Postal Service 513 - - - 1.32 10% 60% 30%

90.0000 Other value added n.a. 40.38 71.05 11.32 30.90 0% 20% 80%

88.0000 Compensation of Employees n.a. n.a. n.a. n.a.

Exhibit 6-4: Percentage Estimates of Purchased Services by Sector and Geographic Area For Support Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Percent of Labor Compensation Percent of Purchased Services

Investment Finance Charges

Note that one BEA sector, "Other Value Added", is not assigned directly to an IMPLAN sector. 

This category is comprised of capital depreciation and finance charges. Mining industries are

different from other production oriented industries (e.g., manufacturing) in that they are very

capital intensive and a large percentage of their total expenditures falls under research and

development (R&D), which can be capitalized. As a result, mining industries incur relative high 

finance charges to cover these capital and R&D expenditures. In the National Input-Output 
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 145 Arctic IMPAK

Accounts, these types of finance charges are grouped with depreciation charges under the

category called "Other Value Added."

In Chapter Seven, we explicitly addressed capital depreciation by spreading equipment

expenditures over the lives of the assets and taking into account usage rates. To account for

finance charges, we started by calculating total other value added for each activity. This was

accomplished by multiplying each activity's employee compensation estimate by a

corresponding ratio of Other Value Added to Employee Compensation (calculated using the

National Input-Output tables). The results were then divided in half to eliminate the depreciation 

charges (this is based on the assumption that finance charges are paid monthly over a 20 year

period at an 8 percent interest rate). The resulting interest payments were further divided and

assigned to the sources of the funds. Some of the charges reflect a return to personal savings and 

were assigned to PCE accordingly. The remaining charges represent returns to financial service 

industries and were distributed between the banking industry (IMPLAN sector 456), credit

agencies (IMPLAN Sector 457) and security/commodity brokers (IMPLAN sector 458).

It should be noted that some of the finance charges occur only in one time period whereas others 

span a number of years. This is to be expected and reflects the different nature of capital

investments being financed. The first case is generally associated with the use of equipment to

carry out a specific project: for example, using a bulldozer to help build an ice road. In this

example, a small fraction of the total finance charges the contractor incurred when he purchased 

the bulldozer are expensed to the project based upon how much the machine is used. Finance

charges paid over multiple years include not only equipment usage, but also the capitalization of 

labor, materials and installed equipment needed to conduct research and development. In

IMPAK, such charges are tied to oil production operations.

6.3 PURCHASED SERVICES BY GEOGRAPHIC AREA

The estimates of purchased services by activity and IMPLAN sector are then split among the

local area, the rest of Alaska and the 49 states. This disaggregation is based on percentage

distributions developed by engineering study staff, based on their familiarity with the area and

the production process. These percentages are provided in Exhibits 6-3 and 6-4. The percentage 

estimates provided in Exhibit 6-3 are for the oil and gas sectors, while those in Exhibit 6-4 are

used for the hotel, air and water sectors. In each exhibit, separate percentages are provided for

projects located in the Cook Inlet, remote locations and remote location near areas of labor

availability.

6.4 FINAL ESTIMATES OF PURCHASED SERVICES

The final estimates of purchased services inputs by activity, input sector and geographic area are 

found by multiplying the national input-output ratios by the labor compensation calculated for

sub-arctic Alaska and the percentages for geographic areas. These final estimates are provided
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 146 Arctic IMPAK

in Exhibit 6-5. Exhibit 6-5 includes a specific table of results for each of the 26 activities

included in the IMPAK model.

Activity # 1. Geological Survey

66.0100 Telephone communications 441 11,078 2,216 6,647 2,216

70.0100 Banking 456 28,214 1,411 16,929 9,875

70.0400 Insurance carriers 459 5,626 - 3,375 2,250

71.0201 Real estate agents 462 27,738 2,774 13,869 11,095

72.0101 Hotels 463 13,155 658 6,578 5,920

73.0103 Personnel supply 474 7,703 1,155 3,851 2,696

73.0104 Computers & data processing 475 5,885 1,471 2,354 2,060

73.0111 Management & consulting 508 6,837 684 3,419 2,735

73.0200 Advertising 469 7,010 - 2,804 4,206

73.0301 Legal services 494 46,995 - 18,798 28,197

73.0302 Engineering, architectural & surveying 506 37,821 5,673 17,020 15,128

73.0303 Accounting, auditing & bookeeping 507 2,077 208 1,246 623

74.0000 Eating & drinking places 454 15,579 779 7,789 7,010

75.0001 Automotive rental & leasing 477 4,803 961 2,402 1,441

77.0501 Associations & professional org. 503 3,029 - 1,212 1,817

90.0000 Other value added n.a. 695,364 - 139,073 556,291

88.0000 Compensation of Employees n.a. 983,047 n.a. n.a. n.a.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases NSB Other Alaska Other U.S.

Activity # 2. North Slope Support

66.0100 Telephone communications 441 65,315 130.63 391.89 130.63

66.0200 Cable TV 441 66,395 132.79 398.37 132.79

70.0100 Banking 456 300,486 150.24 1,802.92 1,051.70

70.0200 Credit agencies 457 240,209 120.10 1,441.25 840.73

70.0400 Insurance carriers 459 0 - - -

71.0201 Real estate agents 462 243,448 243.45 1,217.24 973.79

73.0102 Services to dwellings/buildings 472 111,378 111.38 668.27 334.13

73.0103 Personnel supply 474 90,686 136.03 453.43 317.40

73.0104 Computers & data processing 475 61,357 153.39 245.43 214.75

73.0106 Detective services 476 73,052 73.05 438.31 219.16

73.0107 Equipment rental & leasing 473 0 - - -

73.0109 Other business services 470 169,316 - - -

73.0111 Management & consulting 508 174,714 174.71 873.57 698.85

73.0112 Testing and research labs 509 0 - - -

73.0200 Advertising 469 175,253 - 701.01 1,051.52

73.0301 Legal services 494 52,000 - 312.00 208.00

73.0302 Engineering, architectural & surveying 506 0 - - -

73.0303 Accounting, auditing & bookeeping 507 0 - - -

74.0000 Eating & drinking places 454 53,620 26.81 268.10 241.29

75.0001 Automotive rental & leasing 477 0 - - -

78.0100 U.S. Postal Service 513 47,502 47.50 285.01 142.51

90.0000 Other value added n.a. 1,108,199 - 2,216.40 8,865.59

88.0000 Compensation of Employees n.a. 3,586,758

Other U.S.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name IMPLAN Sector

Service 

Purchases NSB Other Alaska
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 147 Arctic IMPAK

Activity # 3. General Personnel Transport

66.0100 Telephone communications 441 150 0.3 0.9 0.3

66.0200 Cable TV 441 - - - -

70.0100 Banking 456 73 0.0 0.4 0.3

70.0200 Credit agencies 457 - - - -

70.0400 Insurance carriers 459 68 - 0.4 0.3

71.0201 Real estate agents 462 130 0.1 0.7 0.5

73.0102 Services to dwellings/buildings 472 - - - -

73.0103 Personnel supply 474 186 0.3 0.9 0.7

73.0104 Computers & data processing 475 - - - -

73.0106 Detective services 476 - - - -

73.0107 Equipment rental & leasing 473 - - - -

73.0109 Other business services 470 - - - -

73.0111 Management & consulting 508 - - - -

73.0112 Testing and research labs 509 - - - -

73.0200 Advertising 469 - - - -

73.0301 Legal services 494 82 - 0.5 0.3

73.0302 Engineering, architectural & surveying 506 - - - -

73.0303 Accounting, auditing & bookeeping 507 - - - -

74.0000 Eating & drinking places 454 - - - -

75.0001 Automotive rental & leasing 477 141 0.3 0.7 0.4

78.0100 U.S. Postal Service 513 - - - -

90.0000 Other value added n.a. 1,520 - 3.0 12.2

88.0000 Compensation of Employees n.a. 3,764

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name IMPLAN Sector

Service 

Purchases NSB Other Alaska Other U.S.

Activity # 4. Construct Ice Road

66.0100 Telephone communications 441 9,485 1,897 5,691 1,897

70.0100 Banking 456 24,158 1,208 14,495 8,455

70.0400 Insurance carriers 459 4,817 - 2,890 1,927

71.0201 Real estate agents 462 23,751 2,375 11,875 9,500

72.0101 Hotels 463 11,264 563 5,632 5,069

73.0103 Personnel supply 474 6,595 989 3,298 2,308

73.0104 Computers & data processing 475 5,039 1,260 2,016 1,764

73.0111 Management & consulting 508 5,854 585 2,927 2,342

73.0200 Advertising 469 6,003 - 2,401 3,602

73.0301 Legal services 494 40,239 - 16,096 24,144

73.0302 Engineering, architectural & surveying 506 32,384 4,858 14,573 12,954

73.0303 Accounting, auditing & bookeeping 507 1,779 178 1,067 534

74.0000 Eating & drinking places 454 13,339 667 6,669 6,003

75.0001 Automotive rental & leasing 477 4,113 823 2,056 1,234

77.0501 Associations & professional org. 503 2,594 - 1,037 1,556

90.0000 Other value added n.a. 595,399 - 119,080 476,319

88.0000 Compensation of Employees n.a. 841,725 n.a. n.a. n.a.

NSB Other Alaska Other U.S.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 148 Arctic IMPAK

Activity # 5. Construct Ice Island

66.0100 Telephone communications 441 5,667 1,133 3,400 1,133

70.0100 Banking 456 14,433 722 8,660 5,051

70.0400 Insurance carriers 459 2,878 - 1,727 1,151

71.0201 Real estate agents 462 14,189 1,419 7,095 5,676

72.0101 Hotels 463 6,729 336 3,365 3,028

73.0103 Personnel supply 474 3,940 591 1,970 1,379

73.0104 Computers & data processing 475 3,010 753 1,204 1,054

73.0111 Management & consulting 508 3,497 350 1,749 1,399

73.0200 Advertising 469 3,586 - 1,434 2,152

73.0301 Legal services 494 24,040 - 9,616 14,424

73.0302 Engineering, architectural & surveying 506 19,347 2,902 8,706 7,739

73.0303 Accounting, auditing & bookeeping 507 1,063 106 638 319

74.0000 Eating & drinking places 454 7,969 398 3,984 3,586

75.0001 Automotive rental & leasing 477 2,457 491 1,229 737

77.0501 Associations & professional org. 503 1,550 - 620 930

90.0000 Other value added n.a. 355,701 - 71,140 284,561

88.0000 Compensation of Employees n.a. 502,860 n.a. n.a. n.a.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases NSB Other Alaska Other U.S.

Activity # 6. Move Drll Ship/Bottom Founded Platform

66.0100 Telephone communications 441 1,094 219 656 219

70.0100 Banking 456 2,785 139 1,671 975

70.0400 Insurance carriers 459 555 - 333 222

71.0201 Real estate agents 462 2,738 274 1,369 1,095

72.0101 Hotels 463 1,299 65 649 584

73.0103 Personnel supply 474 760 114 380 266

73.0104 Computers & data processing 475 581 145 232 203

73.0111 Management & consulting 508 675 67 337 270

73.0200 Advertising 469 692 - 277 415

73.0301 Legal services 494 4,639 - 1,856 2,784

73.0302 Engineering, architectural & surveying 506 3,734 560 1,680 1,493

73.0303 Accounting, auditing & bookeeping 507 205 21 123 62

74.0000 Eating & drinking places 454 1,538 77 769 692

75.0001 Automotive rental & leasing 477 474 95 237 142

77.0501 Associations & professional org. 503 299 - 120 179

90.0000 Other value added n.a. 68,647 - 13,729 54,918

88.0000 Compensation of Employees n.a. 97,047 n.a. n.a. n.a.

NSB Other Alaska Other U.S.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 149 Arctic IMPAK

Activity # 7. Operate Drill Ship in Calm Waters

66.0100 Telephone communications 441 234 47 140 47

70.0100 Banking 456 595 30 357 208

70.0400 Insurance carriers 459 119 - 71 47

71.0201 Real estate agents 462 585 59 293 234

72.0101 Hotels 463 278 14 139 125

73.0103 Personnel supply 474 163 24 81 57

73.0104 Computers & data processing 475 124 31 50 43

73.0111 Management & consulting 508 144 14 72 58

73.0200 Advertising 469 148 - 59 89

73.0301 Legal services 494 992 - 397 595

73.0302 Engineering, architectural & surveying 506 798 120 359 319

73.0303 Accounting, auditing & bookeeping 507 44 4 26 13

74.0000 Eating & drinking places 454 329 16 164 148

75.0001 Automotive rental & leasing 477 101 20 51 30

77.0501 Associations & professional org. 503 64 - 26 38

90.0000 Other value added n.a. 14,671 - 2,934 11,737

88.0000 Compensation of Employees n.a. 20,741 n.a. n.a. n.a.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases NSB Other Alaska Other U.S.

Activity # 8. Operate Drill Ship in Rough Seas

66.0100 Telephone communications 441 1,094 219 656 219

70.0100 Banking 456 2,785 139 1,671 975

70.0400 Insurance carriers 459 555 - 333 222

71.0201 Real estate agents 462 2,738 274 1,369 1,095

72.0101 Hotels 463 1,299 65 649 584

73.0103 Personnel supply 474 760 114 380 266

73.0104 Computers & data processing 475 581 145 232 203

73.0111 Management & consulting 508 675 67 337 270

73.0200 Advertising 469 692 - 277 415

73.0301 Legal services 494 4,639 - 1,856 2,784

73.0302 Engineering, architectural & surveying 506 3,734 560 1,680 1,493

73.0303 Accounting, auditing & bookeeping 507 205 21 123 62

74.0000 Eating & drinking places 454 1,538 77 769 692

75.0001 Automotive rental & leasing 477 474 95 237 142

77.0501 Associations & professional org. 503 299 - 120 179

90.0000 Other value added n.a. 68,647 - 13,729 54,918

88.0000 Compensation of Employees n.a. 97,047 n.a. n.a. n.a.

NSB Other Alaska Other U.S.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 150 Arctic IMPAK

Activity # 9. Operate Mobile Exploration Platform

66.0100 Telephone communications 441 225 45 135 45

70.0100 Banking 456 573 29 344 201

70.0400 Insurance carriers 459 114 - 69 46

71.0201 Real estate agents 462 564 56 282 226

72.0101 Hotels 463 267 13 134 120

73.0103 Personnel supply 474 157 23 78 55

73.0104 Computers & data processing 475 120 30 48 42

73.0111 Management & consulting 508 139 14 69 56

73.0200 Advertising 469 142 - 57 85

73.0301 Legal services 494 955 - 382 573

73.0302 Engineering, architectural & surveying 506 769 115 346 307

73.0303 Accounting, auditing & bookeeping 507 42 4 25 13

74.0000 Eating & drinking places 454 317 16 158 142

75.0001 Automotive rental & leasing 477 98 20 49 29

77.0501 Associations & professional org. 503 62 - 25 37

90.0000 Other value added n.a. 14,133 - 2,827 11,306

88.0000 Compensation of Employees n.a. 19,980 n.a. n.a. n.a.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases NSB Other Alaska Other U.S.

Activity # 10. Helicopter Support

66.0100 Telephone communications 441 144 0.3 0.9 0.3

66.0200 Cable TV 441 - - - -

70.0100 Banking 456 72 0.0 0.4 0.3

70.0200 Credit agencies 457 94 0.0 0.6 0.3

70.0400 Insurance carriers 459 - - - -

71.0201 Real estate agents 462 171 0.2 0.9 0.7

73.0102 Services to dwellings/buildings 472 - - - -

73.0103 Personnel supply 474 - - - -

73.0104 Computers & data processing 475 267 0.7 1.1 0.9

73.0106 Detective services 476 - - - -

73.0107 Equipment rental & leasing 473 81 0.1 0.5 0.2

73.0109 Other business services 470 - - - -

73.0111 Management & consulting 508 - - - -

73.0112 Testing and research labs 509 - - - -

73.0200 Advertising 469 166 - 0.7 1.0

73.0301 Legal services 494 113 - 0.7 0.5

73.0302 Engineering, architectural & surveying 506 - - - -

73.0303 Accounting, auditing & bookeeping 507 - - - -

74.0000 Eating & drinking places 454 220 0.1 1.1 1.0

75.0001 Automotive rental & leasing 477 - - - -

78.0100 U.S. Postal Service 513 - - - -

90.0000 Other value added n.a. 445 - 0.9 3.6

88.0000 Compensation of Employees n.a. 3,927

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name IMPLAN Sector

Service 

Purchases NSB Other Alaska Other U.S.
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DOI-MMS 151 Arctic IMPAK

Activity # 11. Barge Support

66.0100 Telephone communications 441 - - - -

66.0200 Cable TV 441 - - - -

70.0100 Banking 456 132 0.1 0.8 0.5

70.0200 Credit agencies 457 148 0.1 0.9 0.5

70.0400 Insurance carriers 459 - - - -

71.0201 Real estate agents 462 246 0.2 1.2 1.0

73.0102 Services to dwellings/buildings 472 - - - -

73.0103 Personnel supply 474 - - - -

73.0104 Computers & data processing 475 79 0.2 0.3 0.3

73.0106 Detective services 476 - - - -

73.0107 Equipment rental & leasing 473 52 0.1 0.3 0.2

73.0109 Other business services 470 56 - - -

73.0111 Management & consulting 508 256 0.3 1.3 1.0

73.0112 Testing and research labs 509 209 - 0.4 1.7

73.0200 Advertising 469 349 - 1.4 2.1

73.0301 Legal services 494 46 - 0.3 0.2

73.0302 Engineering, architectural & surveying 506 85 0.1 0.4 0.3

73.0303 Accounting, auditing & bookeeping 507 61 0.1 0.4 0.2

74.0000 Eating & drinking places 454 - - - -

75.0001 Automotive rental & leasing 477 - - - -

78.0100 U.S. Postal Service 513 - - - -

90.0000 Other value added n.a. 1,424 - 2.8 11.4

88.0000 Compensation of Employees n.a. 2,004

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name IMPLAN Sector

Service 

Purchases NSB Other Alaska Other U.S.

Activity # 12. Drill Exploration Well

66.0100 Telephone communications 441 36,194 7,239 21,717 7,239

70.0100 Banking 456 92,182 4,609 55,309 32,264

70.0400 Insurance carriers 459 18,380 - 11,028 7,352

71.0201 Real estate agents 462 90,627 9,063 45,313 36,251

72.0101 Hotels 463 42,981 2,149 21,490 19,341

73.0103 Personnel supply 474 25,166 3,775 12,583 8,808

73.0104 Computers & data processing 475 19,228 4,807 7,691 6,730

73.0111 Management & consulting 508 22,339 2,234 11,169 8,935

73.0200 Advertising 469 22,904 - 9,162 13,742

73.0301 Legal services 494 153,543 - 61,417 92,126

73.0302 Engineering, architectural & surveying 506 123,569 18,535 55,606 49,428

73.0303 Accounting, auditing & bookeeping 507 6,786 679 4,072 2,036

74.0000 Eating & drinking places 454 50,898 2,545 25,449 22,904

75.0001 Automotive rental & leasing 477 15,694 3,139 7,847 4,708

77.0501 Associations & professional org. 503 9,897 - 3,959 5,938

90.0000 Other value added n.a. 2,271,894 - 454,379 1,817,515

88.0000 Compensation of Employees n.a. 3,211,813 n.a. n.a. n.a.

NSB Other Alaska Other U.S.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 152 Arctic IMPAK

Activity # 13. Drill Production Well

66.0100 Telephone communications 441 12,065 2,413 7,239 2,413

70.0100 Banking 456 30,727 1,536 18,436 10,755

70.0400 Insurance carriers 459 6,127 - 3,676 2,451

71.0201 Real estate agents 462 30,209 3,021 15,104 12,084

72.0101 Hotels 463 14,327 716 7,163 6,447

73.0103 Personnel supply 474 8,389 1,258 4,194 2,936

73.0104 Computers & data processing 475 6,409 1,602 2,564 2,243

73.0111 Management & consulting 508 7,446 745 3,723 2,978

73.0200 Advertising 469 7,635 - 3,054 4,581

73.0301 Legal services 494 51,181 - 20,472 30,709

73.0302 Engineering, architectural & surveying 506 41,190 6,178 18,535 16,476

73.0303 Accounting, auditing & bookeeping 507 2,262 226 1,357 679

74.0000 Eating & drinking places 454 16,966 848 8,483 7,635

75.0001 Automotive rental & leasing 477 5,231 1,046 2,616 1,569

77.0501 Associations & professional org. 503 3,299 - 1,320 1,979

90.0000 Other value added n.a. 757,298 - 151,460 605,838

88.0000 Compensation of Employees n.a. 1,070,604 n.a. n.a. n.a.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases NSB Other Alaska Other U.S.

Activity # 14. Well Workover

66.0100 Telephone communications 441 1,609 322 965 322

70.0100 Banking 456 4,097 205 2,458 1,434

70.0400 Insurance carriers 459 817 - 490 327

71.0201 Real estate agents 462 4,028 403 2,014 1,611

72.0101 Hotels 463 1,910 96 955 860

73.0103 Personnel supply 474 1,119 168 559 391

73.0104 Computers & data processing 475 855 214 342 299

73.0111 Management & consulting 508 993 99 496 397

73.0200 Advertising 469 1,018 - 407 611

73.0301 Legal services 494 6,824 - 2,730 4,094

73.0302 Engineering, architectural & surveying 506 5,492 824 2,471 2,197

73.0303 Accounting, auditing & bookeeping 507 302 30 181 90

74.0000 Eating & drinking places 454 2,262 113 1,131 1,018

75.0001 Automotive rental & leasing 477 697 139 349 209

77.0501 Associations & professional org. 503 440 - 176 264

90.0000 Other value added n.a. 100,973 - 20,195 80,778

88.0000 Compensation of Employees n.a. 142,747 n.a. n.a. n.a.

NSB Other Alaska Other U.S.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 153 Arctic IMPAK

Activity # 15. Construct Gravel Island

66.0100 Telephone communications 441 32,336 6,467 19,402 6,467

70.0100 Banking 456 82,356 4,118 49,414 28,825

70.0400 Insurance carriers 459 16,421 - 9,852 6,568

71.0201 Real estate agents 462 80,967 8,097 40,483 32,387

72.0101 Hotels 463 38,399 1,920 19,200 17,280

73.0103 Personnel supply 474 22,484 3,373 11,242 7,869

73.0104 Computers & data processing 475 17,179 4,295 6,871 6,013

73.0111 Management & consulting 508 19,958 1,996 9,979 7,983

73.0200 Advertising 469 20,463 - 8,185 12,278

73.0301 Legal services 494 137,176 - 54,871 82,306

73.0302 Engineering, architectural & surveying 506 110,398 16,560 49,679 44,159

73.0303 Accounting, auditing & bookeeping 507 6,063 606 3,638 1,819

74.0000 Eating & drinking places 454 45,473 2,274 22,736 20,463

75.0001 Automotive rental & leasing 477 14,021 2,804 7,010 4,206

77.0501 Associations & professional org. 503 8,842 - 3,537 5,305

90.0000 Other value added n.a. 2,029,729 - 405,946 1,623,783

88.0000 Compensation of Employees n.a. 2,869,460 n.a. n.a. n.a.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases NSB Other Alaska Other U.S.

Activity # 16. Protect Gravel Island

66.0100 Telephone communications 441 78,532 15,706 47,119 15,706

70.0100 Banking 456 200,012 10,001 120,007 70,004

70.0400 Insurance carriers 459 39,880 - 23,928 15,952

71.0201 Real estate agents 462 196,637 19,664 98,319 78,655

72.0101 Hotels 463 93,257 4,663 46,629 41,966

73.0103 Personnel supply 474 54,604 8,191 27,302 19,112

73.0104 Computers & data processing 475 41,720 10,430 16,688 14,602

73.0111 Management & consulting 508 48,469 4,847 24,235 19,388

73.0200 Advertising 469 49,696 - 19,878 29,818

73.0301 Legal services 494 333,149 - 133,259 199,889

73.0302 Engineering, architectural & surveying 506 268,114 40,217 120,651 107,246

73.0303 Accounting, auditing & bookeeping 507 14,725 1,472 8,835 4,417

74.0000 Eating & drinking places 454 110,436 5,522 55,218 49,696

75.0001 Automotive rental & leasing 477 34,051 6,810 17,026 10,215

77.0501 Associations & professional org. 503 21,474 - 8,589 12,884

90.0000 Other value added n.a. 4,929,434 - 985,887 3,943,547

88.0000 Compensation of Employees n.a. 6,968,818 n.a. n.a. n.a.

NSB Other Alaska Other U.S.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 154 Arctic IMPAK

Activity # 17. Equip Production Island

66.0100 Telephone communications 441 143,613 28,723 86,168 28,723

70.0100 Banking 456 365,765 18,288 219,459 128,018

70.0400 Insurance carriers 459 72,929 - 43,757 29,171

71.0201 Real estate agents 462 359,594 35,959 179,797 143,838

72.0101 Hotels 463 170,541 8,527 85,270 76,743

73.0103 Personnel supply 474 99,856 14,978 49,928 34,950

73.0104 Computers & data processing 475 76,295 19,074 30,518 26,703

73.0111 Management & consulting 508 88,636 8,864 44,318 35,455

73.0200 Advertising 469 90,880 - 36,352 54,528

73.0301 Legal services 494 609,235 - 243,694 365,541

73.0302 Engineering, architectural & surveying 506 490,305 73,546 220,637 196,122

73.0303 Accounting, auditing & bookeeping 507 26,928 2,693 16,157 8,078

74.0000 Eating & drinking places 454 201,956 10,098 100,978 90,880

75.0001 Automotive rental & leasing 477 62,270 12,454 31,135 18,681

77.0501 Associations & professional org. 503 39,269 - 15,708 23,562

90.0000 Other value added n.a. 9,014,544 - 1,802,909 7,211,635

88.0000 Compensation of Employees n.a. 12,744,004 n.a. n.a. n.a.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases NSB Other Alaska Other U.S.

Activity # 18. Operate Production Island

66.0100 Telephone communications 441 187,086 37,417 112,251 37,417

70.0100 Banking 456 476,484 23,824 285,890 166,769

70.0400 Insurance carriers 459 95,004 - 57,003 38,002

71.0201 Real estate agents 462 468,445 46,845 234,223 187,378

72.0101 Hotels 463 222,164 11,108 111,082 99,974

73.0103 Personnel supply 474 130,083 19,512 65,042 45,529

73.0104 Computers & data processing 475 99,389 24,847 39,756 34,786

73.0111 Management & consulting 508 115,467 11,547 57,733 46,187

73.0200 Advertising 469 118,390 - 47,356 71,034

73.0301 Legal services 494 793,653 - 317,461 476,192

73.0302 Engineering, architectural & surveying 506 638,722 95,808 287,425 255,489

73.0303 Accounting, auditing & bookeeping 507 35,079 3,508 21,047 10,524

74.0000 Eating & drinking places 454 263,089 13,154 131,545 118,390

75.0001 Automotive rental & leasing 477 81,119 16,224 40,560 24,336

77.0501 Associations & professional org. 503 51,156 - 20,462 30,694

90.0000 Other value added n.a. 11,743,282 - 2,348,656 9,394,626

88.0000 Compensation of Employees n.a. 16,601,664 n.a. n.a. n.a.

NSB Other Alaska Other U.S.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 155 Arctic IMPAK

Activity # 19. Construct Gas Production Facility

66.0100 Telephone communications 441 75,563 15,113 45,338 15,113

70.0100 Banking 456 192,450 9,623 115,470 67,358

70.0400 Insurance carriers 459 38,372 - 23,023 15,349

71.0201 Real estate agents 462 189,204 18,920 94,602 75,681

72.0101 Hotels 463 89,731 4,487 44,866 40,379

73.0103 Personnel supply 474 52,540 7,881 26,270 18,389

73.0104 Computers & data processing 475 40,143 10,036 16,057 14,050

73.0111 Management & consulting 508 46,637 4,664 23,318 18,655

73.0200 Advertising 469 47,817 - 19,127 28,690

73.0301 Legal services 494 320,554 - 128,222 192,332

73.0302 Engineering, architectural & surveying 506 257,978 38,697 116,090 103,191

73.0303 Accounting, auditing & bookeeping 507 14,168 1,417 8,501 4,250

74.0000 Eating & drinking places 454 106,261 5,313 53,130 47,817

75.0001 Automotive rental & leasing 477 32,764 6,553 16,382 9,829

77.0501 Associations & professional org. 503 20,662 - 8,265 12,397

90.0000 Other value added n.a. 4,743,077 - 948,615 3,794,461

88.0000 Compensation of Employees n.a. 6,705,362 n.a. n.a. n.a.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases NSB Other Alaska Other U.S.

Activity # 20. Operate Gas Production Facility

66.0100 Telephone communications 441 15,773 3,155 9,464 3,155

70.0100 Banking 456 40,171 2,009 24,103 14,060

70.0400 Insurance carriers 459 8,010 - 4,806 3,204

71.0201 Real estate agents 462 39,493 3,949 19,747 15,797

72.0101 Hotels 463 18,730 937 9,365 8,429

73.0103 Personnel supply 474 10,967 1,645 5,483 3,838

73.0104 Computers & data processing 475 8,379 2,095 3,352 2,933

73.0111 Management & consulting 508 9,735 973 4,867 3,894

73.0200 Advertising 469 9,981 - 3,992 5,989

73.0301 Legal services 494 66,911 - 26,764 40,146

73.0302 Engineering, architectural & surveying 506 53,849 8,077 24,232 21,540

73.0303 Accounting, auditing & bookeeping 507 2,957 296 1,774 887

74.0000 Eating & drinking places 454 22,180 1,109 11,090 9,981

75.0001 Automotive rental & leasing 477 6,839 1,368 3,419 2,052

77.0501 Associations & professional org. 503 4,313 - 1,725 2,588

90.0000 Other value added n.a. 990,045 - 198,009 792,036

88.0000 Compensation of Employees n.a. 1,399,643 n.a. n.a. n.a.

NSB Other Alaska Other U.S.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 156 Arctic IMPAK

Activity # 21. Construct Offshore Pipeline

66.0100 Telephone communications 441 52,145 10,429 31,287 10,429

70.0100 Banking 456 132,808 6,640 79,685 46,483

70.0400 Insurance carriers 459 26,480 - 15,888 10,592

71.0201 Real estate agents 462 130,567 13,057 65,283 52,227

72.0101 Hotels 463 61,923 3,096 30,961 27,865

73.0103 Personnel supply 474 36,257 5,439 18,129 12,690

73.0104 Computers & data processing 475 27,702 6,926 11,081 9,696

73.0111 Management & consulting 508 32,183 3,218 16,092 12,873

73.0200 Advertising 469 32,998 - 13,199 19,799

73.0301 Legal services 494 221,210 - 88,484 132,726

73.0302 Engineering, architectural & surveying 506 178,027 26,704 80,112 71,211

73.0303 Accounting, auditing & bookeeping 507 9,777 978 5,866 2,933

74.0000 Eating & drinking places 454 73,329 3,666 36,665 32,998

75.0001 Automotive rental & leasing 477 22,610 4,522 11,305 6,783

77.0501 Associations & professional org. 503 14,258 - 5,703 8,555

90.0000 Other value added n.a. 3,273,137 - 654,627 2,618,510

88.0000 Compensation of Employees n.a. 4,627,286 n.a. n.a. n.a.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases NSB Other Alaska Other U.S.

Activity # 22. Construct Onshore Pipeline

66.0100 Telephone communications 441 30,194 6,039 18,117 6,039

70.0100 Banking 456 76,901 3,845 46,140 26,915

70.0400 Insurance carriers 459 15,333 - 9,200 6,133

71.0201 Real estate agents 462 75,603 7,560 37,802 30,241

72.0101 Hotels 463 35,856 1,793 17,928 16,135

73.0103 Personnel supply 474 20,994 3,149 10,497 7,348

73.0104 Computers & data processing 475 16,041 4,010 6,416 5,614

73.0111 Management & consulting 508 18,635 1,864 9,318 7,454

73.0200 Advertising 469 19,107 - 7,643 11,464

73.0301 Legal services 494 128,089 - 51,236 76,854

73.0302 Engineering, architectural & surveying 506 103,085 15,463 46,388 41,234

73.0303 Accounting, auditing & bookeeping 507 5,661 566 3,397 1,698

74.0000 Eating & drinking places 454 42,461 2,123 21,230 19,107

75.0001 Automotive rental & leasing 477 13,092 2,618 6,546 3,928

77.0501 Associations & professional org. 503 8,256 - 3,302 4,954

90.0000 Other value added n.a. 1,895,275 - 379,055 1,516,220

88.0000 Compensation of Employees n.a. 2,679,381 n.a. n.a. n.a.

NSB Other Alaska Other U.S.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 157 Arctic IMPAK

Activity # 23. Lay Sea Floor Pipeline

66.0100 Telephone communications 441 81,777 16,355 49,066 16,355

70.0100 Banking 456 208,276 10,414 124,966 72,897

70.0400 Insurance carriers 459 41,527 - 24,916 16,611

71.0201 Real estate agents 462 204,762 20,476 102,381 81,905

72.0101 Hotels 463 97,110 4,856 48,555 43,700

73.0103 Personnel supply 474 56,861 8,529 28,430 19,901

73.0104 Computers & data processing 475 43,444 10,861 17,378 15,205

73.0111 Management & consulting 508 50,472 5,047 25,236 20,189

73.0200 Advertising 469 51,750 - 20,700 31,050

73.0301 Legal services 494 346,914 - 138,765 208,148

73.0302 Engineering, architectural & surveying 506 279,192 41,879 125,636 111,677

73.0303 Accounting, auditing & bookeeping 507 15,333 1,533 9,200 4,600

74.0000 Eating & drinking places 454 114,999 5,750 57,499 51,750

75.0001 Automotive rental & leasing 477 35,458 7,092 17,729 10,637

77.0501 Associations & professional org. 503 22,361 - 8,944 13,417

90.0000 Other value added n.a. 5,133,108 - 1,026,622 4,106,486

88.0000 Compensation of Employees n.a. 7,256,756 n.a. n.a. n.a.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases NSB Other Alaska Other U.S.

Activity # 24. Land Base Operation

66.0100 Telephone communications 441 822,954 164,591 493,772 164,591

70.0100 Banking 456 2,095,961 104,798 1,257,577 733,586

70.0400 Insurance carriers 459 417,906 - 250,744 167,163

71.0201 Real estate agents 462 2,060,600 206,060 1,030,300 824,240

72.0101 Hotels 463 977,258 48,863 488,629 439,766

73.0103 Personnel supply 474 572,210 85,832 286,105 200,274

73.0104 Computers & data processing 475 437,194 109,299 174,878 153,018

73.0111 Management & consulting 508 507,917 50,792 253,959 203,167

73.0200 Advertising 469 520,776 - 208,310 312,465

73.0301 Legal services 494 3,491,126 - 1,396,450 2,094,675

73.0302 Engineering, architectural & surveying 506 2,809,617 421,443 1,264,328 1,123,847

73.0303 Accounting, auditing & bookeeping 507 154,304 15,430 92,582 46,291

74.0000 Eating & drinking places 454 1,157,279 57,864 578,640 520,776

75.0001 Automotive rental & leasing 477 356,828 71,366 178,414 107,048

77.0501 Associations & professional org. 503 225,027 - 90,011 135,016

90.0000 Other value added n.a. 51,656,445 - 10,331,289 41,325,156

88.0000 Compensation of Employees n.a. 73,027,535 n.a. n.a. n.a.

NSB Other Alaska Other U.S.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 158 Arctic IMPAK

Activity # 25. Spill Contingency

66.0100 Telephone communications 441 173,049 34,610 103,829 34,610

70.0100 Banking 456 440,733 22,037 264,440 154,257

70.0400 Insurance carriers 459 87,876 - 52,726 35,151

71.0201 Real estate agents 462 433,298 43,330 216,649 173,319

72.0101 Hotels 463 205,495 10,275 102,748 92,473

73.0103 Personnel supply 474 120,323 18,048 60,161 42,113

73.0104 Computers & data processing 475 91,932 22,983 36,773 32,176

73.0111 Management & consulting 508 106,803 10,680 53,402 42,721

73.0200 Advertising 469 109,507 - 43,803 65,704

73.0301 Legal services 494 734,105 - 293,642 440,463

73.0302 Engineering, architectural & surveying 506 590,799 88,620 265,860 236,320

73.0303 Accounting, auditing & bookeeping 507 32,447 3,245 19,468 9,734

74.0000 Eating & drinking places 454 243,350 12,167 121,675 109,507

75.0001 Automotive rental & leasing 477 75,033 15,007 37,516 22,510

77.0501 Associations & professional org. 503 47,318 - 18,927 28,391

90.0000 Other value added n.a. 10,862,185 - 2,172,437 8,689,748

88.0000 Compensation of Employees n.a. 15,356,043 n.a. n.a. n.a.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases NSB Other Alaska Other U.S.

Activity # 26. Abandon Production Island

66.0100 Telephone communications 441 187,601 37,520 112,561 37,520

70.0100 Banking 456 477,796 23,890 286,678 167,229

70.0400 Insurance carriers 459 95,266 - 57,160 38,106

71.0201 Real estate agents 462 469,735 46,973 234,867 187,894

72.0101 Hotels 463 222,776 11,139 111,388 100,249

73.0103 Personnel supply 474 130,441 19,566 65,221 45,654

73.0104 Computers & data processing 475 99,663 24,916 39,865 34,882

73.0111 Management & consulting 508 115,785 11,578 57,892 46,314

73.0200 Advertising 469 118,716 - 47,486 71,230

73.0301 Legal services 494 795,838 - 318,335 477,503

73.0302 Engineering, architectural & surveying 506 640,481 96,072 288,216 256,192

73.0303 Accounting, auditing & bookeeping 507 35,175 3,518 21,105 10,553

74.0000 Eating & drinking places 454 263,814 13,191 131,907 118,716

75.0001 Automotive rental & leasing 477 81,343 16,269 40,671 24,403

77.0501 Associations & professional org. 503 51,297 - 20,519 30,778

90.0000 Other value added n.a. 11,775,618 - 2,355,124 9,420,494

88.0000 Compensation of Employees n.a. 16,647,377 n.a. n.a. n.a.

NSB Other Alaska Other U.S.

Exhibit 6-5: Estimates of Purchased Services by Sector and Geographic Area For Oil and Gas Related Activities

BEA I-O 

Sector Sector Name

IMPLAN 

Sector

Service 

Purchases

Activity Units

Activity Units 

Barge Support 1 Day 

Camp Support 1 Year 

Drill Ship – Calm Water 1 Day 

Drill Ship – Rough Water 1 Day

Equip Production Island 1 Island 

Exploration Well 1 Well 

Gravel Island 1 Island 

Helicopter Support 1 Day 

Ice Island 1 Island 

Ice Road 10-Miles 

Land Base Operations 1 Year 

Activity Units 

Mobile Bottom Founded Structure 1 Day 

Move Platform 1 Day 

Offshore Pipeline 1 Mile 

Onshore Pipeline 1 Mile 

Personnel Transport 1 Day 

Production Operations 1 Year 

Production Well 1 Well 

Seafloor Tieback Pipeline 10 Miles 

Seismic Survey 1 Month 

Spill Contingency 1 Year 

Well Work-over 1 Well
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 125 Arctic IMPAK

7 CAPITAL INPUTS

Unlike most labor and material inputs which are entirely and immediately consumed in the

production process, capital inputs are used up gradually over time. This defining aspect of

capital requires special attention when utilizing an input-output (I-O) framework to estimate

economic impacts. Capital expenditures are not included in the use coefficients of an industry,

which only account for inputs that are immediately consumed for current production. In an I-O 

model, annualized capital expenditures are included with value added. Unfortunately, these

expenses are frequently aggregated and, without a capital flow matrix, it is not possible to isolate 

specific types of investments or trace the secondary impacts associated with such investments. 

For this reason, exogenous estimates of capital investment are often developed outside of the I-O 

model, and then used as model catalysts along with other direct expenditures.

Capital investments represent a substantial portion of mineral exploration and development

(E&D) expenditures. Due to the harsh environment, this is especially true on Alaska's North

Slope, where many of the machines only last four years and are often operated for long periods

of time without even being turned off. E&D activities require transportation and earth moving

equipment, drilling equipment, et cetera.

This section describes how expenditures for these items were developed and should be used to

stimulate the IMPLAN input-output model. Please note that separate data are not provided for

the two activities specific to the local gas scenario (Construct Gas Production Facility and

Operate Gas Production Facility); capital expenditures for these activities are “rule-of-thumb” 

estimates based on scaled vectors of other activities in the model (Equip Production Island and

Operate Production Island, respectively).

7.1 OVERVIEW

Capital expenditures were estimated by activity, IMPLAN sector and geographic region. The

estimates were developed for the levels of E&D activities comprising the base scenario and

identified in Exhibit 2-2.

The numbers are based upon estimated expenditures for the different assets needed to carry out

each activity. Each capital expenditure is based upon the total delivered price of the asset. This

cost is annualized (based upon the average life of the machine), converted into a "per unit" basis, 

and then divided into its various cost components: i.e., manufacturing, transportation and

wholesale trade, and retrofitting. Each cost category is assigned to an associated IMPLAN

sector.

Finally, regional purchase coefficients (See Glossary and Chapter 3 were used to allocate

expenditures to impacted geographic regions. This allocation is performed for each cost

component. For example, the manufacturing cost of a particular asset may have been assigned to 
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 126 Arctic IMPAK

the contiguous 48-states whereas part of the cost of delivering it to the North Slope may have

been assigned to the NSB.

Information on capital usage and costs were obtained from the engineering reports presented in

Chapter 4. These data were compiled through surveys of construction and mining contractors

and supplemented with professional judgment. Data were gathered on the types of equipment

used, the percentage of equipment purchases that were new versus used, the percentage of time

equipment were devoted to a particular activities, where equipment were obtained, prices at the

factory gate, shipping methods and costs, how much retrofitting was performed and where it was 

done, and wholesale trade margins. Such information was not available for every piece of

machinery and much of it had to be estimated by JFA staff.

7.2 INVENTORY OF ASSETS USED IN EACH E&D ACTIVITY

The first step in the process was to identify the capital assets used in each E&D activity. It

should be noted that much of the equipment has to be retrofitted with special accessories before 

it can be used in the harsh conditions found on the North Slope. These accessories include

insulation, special engine lubricants, and hardware attachments. The accessories associated with 

each primary piece of capital were also identified in this first step.

Developing the capital cost vectors also required dividing the assets into new and used

equipment categories. There is a considerable amount of salvaged equipment that is used on the 

North Slope. Since used equipment is not manufactured, the main economic impacts associated

with the sale of such equipment results from retrofitting, reconditioning, and margin activities. 

These activities, as well as their associated regional purchase coefficients (See Glossary and

Chapter 3), are not the same for new and used equipment. The estimated percentages of assets

that are new and used are based on subjective judgments and take into account relevant

professional experience. 

The number of assets required to carry out one unit of each activity were then estimated. 

7.3 COST ESTIMATES BY ASSET

This step entailed developing a cost estimate for each asset per activity unit. To develop the cost 

estimates, it was necessary to make some assumptions regarding the average life of the machine 

and the amount of time that it is devoted to the particular activity in question. Average life was

used to capitalize the investment in the machine. Dedication to task was needed since some

machinery can be used on multiple projects simultaneously during a given time period. Both of

these numbers are based on professional engineering judgment.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 127 Arctic IMPAK

Total delivery cost was the final information needed to develop the cost estimates. This

information was gathered primarily in contractor surveys. Some of the information had to be

supplemented with additional estimates based upon professional judgment. 

For each activity and asset, a cost estimate was developed using the above information. The total 

delivery cost was multiplied by the number of assets needed, adjusted for the amount of time it

was devoted to the activity, and then divided by the average life of the machine. For each asset

type, this last step means that we are assuming that the age distribution of the current population 

is uniform. We felt that it would be too difficult and too costly to compute this distribution

through survey work. We also had to assume that each asset adheres to a straight line

depreciation schedule. Again, we felt that it would be too costly and would make the model

unnecessarily complicated to develop different depreciation schedules by asset type. We also

didn't feel comfortable using established depreciation schedules at the national level given the

North Slope's harsh environment.

Finally, the cost estimates were converted into a per unit basis by dividing them by the number

of activity units per year.

Table A-1 in Appendix A presents an inventory of the capital assets and per unit costs for each

E&D activity in IMPAK.

7.3.1 Seismic Survey

In Appendix Table A-1, the asset requirements for conducting and supporting seismic ice 

surveys reflect the annualized capital cost to complete one month of survey work supported by a 

100 man camp. It is assumed that much of the equipment will not be refurbished. Due to

economic competition, contractors are required to use the latest innovations which are being

introduced rapidly in some of the seismic and survey technologies.

Asset lifetimes range from 7 to 10 years depending on the type of asset. Equipment dedication 

ranges from a low of 50 percent for general equipment such as loaders to 100 percent for the

more specialized seismic and survey equipment. To put the costs estimates on a per unit basis, it 

was assumed that each piece of equipment could be used four months out of the year for the

survey work.

Information regarding the equipment used for ice surveys was gathered from contractors engaged 

in conducting ice surveys as well as those who provide camp support for the survey crews.

7.3.2 North Slope Camp Support

In Appendix A, Table A-1, the asset requirements and annual capital costs are provided for 

North Slope Camp Support. Some of the assumed lifetimes are somewhat shorter than might be 
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expected to take into account major overhauls and refurbishments: i.e., these activities are treated 

similar to the purchase of a used piece of machinery. All of the equipment is 100 percent

dedicated to camp support.

As can be seen, most of the capital assets are large expensive pieces of equipment with relatively 

long lifetimes. Purchases of smaller assets such as sewage and water pipe were captured in the

annual maintenance expenditures. Included in the itemized expenditures are charges for

installation/construction and finance. It should be noted that the economic impacts of the

installation and actual equipment costs (net of finance) will occur in the year in which the

equipment was acquired; they will not be felt over the life of the asset. However, for these large 

types of assets, replacement investment (beyond that captured in maintenance charges) will take

place over their lifetimes. Secondary data sources have indicated that annual replacement

investment is roughly equal to depreciation charges, so depreciation is used as a proxy for

replacement investment. 

Information regarding the equipment used to provide food, lodging and other related activities

were gathered from contractors engaged in providing camp support.

7.3.3 General Personnel Transport (GPT)

As shown in Table A-1 in Appendix A, the assets needed for one operation that provides GPT 

services was estimated to be three vans and one bus. 

A large percentage of the capital expenditures are accounted for by refurbishments. Lifetimes

for the vehicles were assumed to be 9 years, with major overhauls conducted every three years.

The vehicles are assumed to be 100 percent dedicated to providing personnel transportation

support for oil exploration and development operations. Dividing the annual capital cost by 365 

yields the daily capital cost for each vehicle.

Information regarding the equipment used to transport personnel to/from the location of E&D

activities were gathered from contractors engaged in providing these activities, as well as

equipment manufactures and suppliers

7.3.4 Ice Roads and Ice Islands

The same type of machinery is used to build both ice islands and ice roads and includes a variety 

of construction vehicles: e.g., snow blowers, graders, dump trucks and water trucks. For each

asset, Table A-1 in Appendix A provides the capital cost to complete a 10-mile ice road that is

five feet deep or one ice island.
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For the most part, lifetimes were assumed to be 12 years, with major overhauls conducted once

every three years. Equipment dedication rates were calculated by dividing the number of days

the machine is used for a given activity by an estimate of the total number of days the machine is 

used each year. 

Information regarding the equipment used to build ice roads and ice islands were gathered from

several construction contractors who provide these services.

7.3.5 Move Platform

Shown in Appendix Table A-1 are the assets required to move drill ships and mobile bottom

founded structures into their operating locations. In addition to the ships and structures

themselves, which move under their own power, other types of vessels are needed to assist in this 

effort. Among these are ice breakers, tugs, workboats and fuel barges. For each asset, the

exhibit provides the annualized capital cost involved in one day of moving operations. 

Asset lifetimes range from 10 to 20 years with all assets assumed to be used. Equipment

dedication was assumed to be 100% once operations are underway. To put the annual costs

estimates on a per day basis, it was assumed that these operations could be conducted 270 days

per year.

7.3.6 Operate Drill Ship for Exploration

The asset requirements for operating drill ships used for exploration purposes are provided in

Appendix Table A-1. For each asset, the exhibit provides the annualized capital cost involved in 

operating the drill ship for one day. Such operations do not include actual drilling activities,

which are addressed separately in Section 7.3.10.

Asset lifetimes range from 10 to 20 years with all assets assumed to be used. Equipment

dedication was assumed to be 100% once operations are underway. To put the annual costs

estimates on a per day basis, it was assumed that the drill ships could operate 270 days per year.

7.3.7 Mobile Bottom Founded Structure (MBFS) for Exploration

The asset requirements for operating an MBFS used for exploration purposes are provided in

Appendix Table A-1. For each asset, the exhibit provides the annualized capital cost involved in 

operating the structure for one day. Such operations do not include actual drilling activities,

which are addressed separately in Section 7.3.10.
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Asset lifetimes range from 10 to 20 years with all assets assumed to be used. Equipment

dedication was assumed to be 100% once operations are underway. To put the annual costs

estimates on a per day basis, it was assumed that the structures could operate 270 days per year.

7.3.8 Helicopter Support

The only asset considered for helicopter support is the actual helicopter. Platform helipads are

taken into account in the chapter dealing with the construction of the platforms. While hangars, 

fuel trucks, and other related assets are utilized by helicopter services, this equipment typically

belongs to the airport where the helicopters are staged.

Lifetimes for the helicopters were assumed to be 15 years, with major overhauls conducted every 

three years. A large percentage of the capital replacements are accounted for by refurbishments.

The helicopters are assumed to be 100 percent dedicated to providing support for oil exploration 

and development operations. However, it is also assumed that the one helicopter can be used to 

support multiple platforms and different types of operations (e.g., ice road construction). 

Dividing the annual capital cost by 365 yields the capital cost per day for the helicopter.

Information regarding the equipment used for helicopter support services was gathered from

contractors engaged in providing these activities, as well as equipment manufactures and

suppliers.

7.3.9 Barge Support

The asset requirements for conducting and supporting barge support are provided in Appendix 

Table A-1. For each asset, the exhibit provides the annualized capital cost for one day of barge

support. 

Asset lifetimes ranged from 3 to 5 years depending on whether the asset was new or used. 

Equipment dedication ranges from a low of 35 percent for general equipment such as loaders to

100 percent for the actual barges. To put the annual costs estimates on a per unit basis, it was

assumed that each piece of equipment could be used four months out of the year.

Information regarding the equipment used for barge support was gathered from contractors

engaged in providing barge support activities.
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7.3.10 Well Drilling

The assets needed to drill production and exploration wells, as well as perform well work-overs, 

are provided in Appendix A, Table A-1. For each asset, the exhibit provides the annual capital

cost to drill one well or perform one well work-over.

A large percentage of the capital replacements are accounted for by refurbishment and the

purchase of used machinery. Lifetimes for the drill rigs were assumed to be 15 years, with major 

overhauls conducted every three years.

The rigs are assumed to be 100 percent dedicated to a given task: i.e., they can't be used on more 

than one task at any give time. However, it is assumed that the same rigs are used to drill both

exploration and production wells, and that one rig can drill one exploration well and six

production wells per year. Taking into account the amount of time it takes to drill each type of

well and to move the rig between wells, it is assumed that the rigs are utilized 270 days per year. 

 Dividing the annual capital cost by 270 yields the daily capital cost for the rig. To put the cost

on a per-well basis, this figure is then multiplied by the number of days it takes to drill a well. It 

is assumed that each work-over rig, which are considerably smaller than the production rigs, is

utilized 120 days per year and that an average work-over takes four days.

All of the equipment was assumed to be manufactured outside of Alaska. Unlike most of the

other heavy equipment, the drill rigs are sometimes transported by Hercules aircraft; therefore,

part of the freight transportation margins were assigned to the air sector.

Information regarding the equipment used for drilling operations was gathered from contractors

engaged in providing these activities, as well as equipment manufactures and suppliers.

7.3.11 Gravel Island Construction

As shown in Appendix Table A-1, the asset requirements to build one gravel island included pile 

drivers, cranes, welding equipment, and other machinery needed to mine, haul and move sand,

gravel and concrete blocks. 

Acquisition costs reflect the total delivered cost to the North Slope. To keep the methodology on 

a consistent basis, in some instances acquisition costs had to be estimated using equipment lease 

rates. This was accomplished by using the ratio of owner capital charges (depreciation plus

interest) per day to daily lease rates for equipment where both data were available.

Most lifetimes were assumed to be 12 years, with major overhauls conducted once every three

years. Equipment dedication rates were calculated by dividing the number of days the machine

is used for a given activity by an estimate of the total number of days the machine is used each
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year. Note that some of the equipment is listed more than once. In these cases, the equipment is 

used at different rates (e.g., 30 days vs. 90 days) in more than one task (e.g., gravel mining and

installation of concrete module foundations).

Information regarding the equipment used to construct gravel islands were gathered from several 

construction contractors who provide these services.

7.3.12 Production Module Installation

Shown in Appendix Table A-1 are the asset requirements to completely outfit one island with all 

of the equipment needed for production. The assets used for these installation and logistic

activities include cranes, loaders, welding machines, and trailers and steel mats needed to move

the modules across the gravel islands. 

Acquisition costs reflect the total delivered cost to the North Slope. To keep the methodology on 

a consistent basis, in some instances acquisition costs had to be estimated using equipment lease 

rates. This was accomplished by using the ratio of owner capital charges (depreciation plus

interest) per day to daily lease rates for equipment where both data were available. Note that

capital costs for barges and other transportation equipment are not included as those charges are 

included in the transportation margins detailed elsewhere.

Most lifetimes were assumed to be 12 years, with major overhauls conducted once every three

years. Equipment dedication rates were calculated by dividing the number of days the machine

is used for a given activity by an estimate of the total number of days the machine is used each

year. . Note that some of the equipment is listed more than once. In these cases, the equipment

is used at different rates (e.g., 30 days vs. 90 days) in more than one task (e.g., offloading the

modules from barges and installing the modules).

The modules themselves are treated as purchased equipment and cost detail for them is provided 

separately in Exhibit 7-1. The modules are designed to facilitate transportation and installation

and consist of large pieces of machinery housed in metal buildings. In the table, the major pieces 

of equipment are itemized separately. In addition to this detail, the table provides information on 

the cost of fabricating the modules, transportation costs from point of origin to the North Slope,

wholesale trade margins, and finance charges (In the model, finance charges will be assigned to

production operations to ensure they span the life of the equipment). Note that the expenditures

have been assigned to IMPLAN sectors and allocated to regions where the impacts are expected 

to accrue.

Information regarding the production modules and the equipment used to install the modules

were gathered from oil company executives and contractors who provide these services.
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Expenditures for Fabrication and Transportation of Production Modules to Equip One Production Island

North

IMPLAN Slope Other Other

Cost Component Item Sector Description Burrough Alaska US Foreign Total

Process Module Inlet Manifold 303 Pipe, Valves, Pipe Fittings - 43,200 648,000 172,800 864,000

Separator 338 General Industrial Machinery, N.E.C. - 72,000 1,080,000 288,000 1,440,000

Oil Treatment 331 Special Industrial Machinery, N.E.C. - 72,000 1,080,000 288,000 1,440,000

Pumps 332 Pumps and Compressors - 43,200 648,000 172,800 864,000

Instruments 403 Mechanical Measuring Devices - 57,600 864,000 230,400 1,152,000

Compressor Module Turbines 307 Steam Engines and Turbines - 383,000 5,745,000 1,532,000 7,660,000

Dehydrator 338 General Industrial Machinery, N.E.C. - 72,000 1,080,000 288,000 1,440,000

NGL Recovery 338 General Industrial Machinery, N.E.C. - 72,000 1,080,000 288,000 1,440,000

Manifold 303 Pipe, Valves, Pipe Fittings - 30,000 450,000 120,000 600,000

Pumps 332 Pumps and Compressors - 30,000 450,000 120,000 600,000

Utility Module Building 287 Prefabricated Metal Buildings - 480,000 720,000 - 1,200,000

Water Treatment 331 Special Industrial Machinery, N.E.C. - 22,800 342,000 91,200 456,000

Generator 357 Motors and Generators - 189,000 2,835,000 756,000 3,780,000

Warehouse Module Building 287 Prefabricated Metal Buildings - 1,080,000 1,620,000 - 2,700,000

Fuel Tanks Fuel Tanks 284 Fabricated Plate Work - 6,500 97,500 26,000 130,000

Water Tank Water Tank 284 Fabricated Plate Work - 1,500 22,500 6,000 30,000

Living Quarters Building 287 Prefabricated Metal Buildings - 720,000 1,080,000 - 1,800,000

Conex Building 287 Prefabricated Metal Buildings - 32,000 48,000 - 80,000

Well Houses Building 287 Prefabricated Metal Buildings - 848,000 1,272,000 - 2,120,000

Fabrication Capital 392 Shipbuilding and Repairing - 8,008,800 2,669,600 2,669,600 13,348,000

Labor 392 Shipbuilding and Repairing - 21,600,000 7,200,000 7,200,000 36,000,000

Materials 392 Shipbuilding and Repairing - 1,968,000 656,000 656,000 3,280,000

Overhead 392 Shipbuilding and Repairing - 8,208,000 2,736,000 2,736,000 13,680,000

Transportation Rail 433 Railroads and Related Services - 33,750 100,000 - 133,750

Truck 435 Motor Freight Transportation 8,435 25,315 100,000 - 133,750

Water 436 Water Transportation - 185,000 25,000 25,000 235,000

Air 437 Air Transportation 5,625 66,875 25,000 25,000 122,500

Wholesale Trade Wholesale Trade 447 Wholesale Trade 74,490 715,104 700,206 - 1,489,800

TOTAL 88,550 45,065,644 35,373,806 17,690,800 98,218,800

Exhibit 7-1

7.3.13 Production Island Operations

The asset requirements to operate a production operation are relatively minor and include a few

pieces of construction machinery. The large production modules are treated as installed

equipment and considered above under "Equip Production Island". For each asset, Table A-1 in 

Appendix A provides the capital cost to operate a production facility for one year.

Most lifetimes were assumed to be 12 years, with major overhauls conducted once every three

years. Equipment dedication rates were calculated by dividing the number of days the machine

is used for a given activity by an estimate of the total number of days the machine is used each

year. It was assumed that all of the equipment would be 100 percent dedicated to this task.

Information regarding the equipment needed for production operations was gathered from oil

company officials.

7.3.14 Pipelines

Shown in Table A1 in Appendix A are the asset requirements to construct a 10-mile buried

offshore pipeline, a 10-mile onshore pipeline, and a 10-mile seafloor tie-back pipeline. Although 
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the equipment includes welding and pipeline coating equipment as well as a variety of

construction vehicles, it can be seen that the types and quantity of machinery utilized varies

depending on the type of pipeline being constructed.

For the most part, lifetimes were assumed to be 12 years, with major overhauls conducted once

every three years. Equipment dedication rates were calculated by dividing the number of days

the machine is used for a given activity by an estimate of the total number of days the machine is 

used each year.

Information regarding the equipment used to construct the pipelines were gathered from several 

construction contractors who provide these services.

7.3.15 Land Base Operations

The asset requirements to operate a warehousing facility operation for one year include trucks 

and machinery used to move supplies and equipment in and out of inventory. 

Most lifetimes were assumed to be 12 years, with major overhauls conducted once every three

years. Equipment dedication rates were calculated by dividing the number of days the machine

is used for a given activity by an estimate of the total number of days the machine is used each

year. It was assumed that all of equipment would be 100 percent dedicated to this task.

It should be noted that maintenance and repair of building capital were treated somewhat

differently. It was estimated that approximately seven million dollars per year would be spent on 

such services. This amount was assigned to IMPLAN sector 56 (Maintenance and Repair of

Nonresidential Facilities). 

Information regarding the equipment needed for warehouse operations was gathered from oil

company officials and contractors who provide these services.

7.3.16 Spill Contingency

Appendix Table A-1 shows the assets needed to operate a spill containment operation for one

year.

Asset lifetimes ranged from 8 to 10 years and all equipment is assumed to be 100 percent

dedicated to spill containment. Given the more stringent spill contingency mandates that were

implemented after the Exxon Valdez oil spill, it is assumed that all depreciated capital will be

replaced with new equipment.

Information regarding the equipment used for spill contingency efforts was gathered from a

co-op engaged in providing these activities, as well as equipment manufactures and suppliers.
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7.3.17 Mobile Bottom Founded Structure (MBFS) for Production

Occasionally, an MBFS being used for exploration purposes is converted into a permanent

production platform. When this happens, the full cost of the structure must be assigned to the

project, which is the same way the production modules were treated in Section 7.3.12 above. 

The acquisition cost of an MBFS was estimated to be $236 million. This value was assigned to

IMPLAN's shipbuilding industry (Sector 392), with 71% allocated to Other Alaska, 19%

allocated to Other US, and 10% allocated to Foreign. 

7.4 MARGINS

The cost estimates developed above reflect the total delivered price of the asset. This price

includes not only the manufacturing price but also trade and transportation margins as well as

additional labor for retrofitting. To be used in the I-O model, it was necessary to break out these 

expenditures from the total delivery price. This was accomplished by developing a margin

matrix (See definition of margin rates in Glossary). For each asset, the margin matrix (Table A-2 

and Table A-3 in Appendix A) shows the percentage of the delivery price that can be attributed

to the following categories:

• Production

Transportation to Alaska

• Rail

• Water

• Truck

• Air

Transportation Within Alaska

• Rail

• Water

• Truck

• Air

• Wholesale Trade

• Retrofitting

During the contractor interviews conducted for the study, data was gathered on production costs, 

transportation costs to Alaska, transportation costs within Alaska, wholesale trade, and

retrofitting. Secondary data sources were used to develop the modal detail for the transportation 
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cost categories; these include the 1993 Commodity Flow Survey and other sources available

from the U.S. Department of Commerce (e.g., the economic censuses, county business patterns,

etc.). Data are extremely sparse in this area and in some instances we had to rely upon IMPLAN 

data or professional judgment.

7.5 REGIONAL PURCHASE COEFFICIENTS (RPC)

After each asset's total delivered price had been split into the above expenditure categories, it

was necessary to assign the expenditures to geographic locales. This was accomplished through

a regional purchase coefficient (See Glossary for definition) matrix, which allocates the

expenditures to four geographic areas: the North Slope Borough, Other Alaska, Other US, and

Foreign. The geographic definitions were determined in part by MMS's need for equitable

sharing analysis.

By associating the expenditures with the areas in which they take place, this step helps to ensure 

that both the direct and indirect regional impacts of an investment are accurately gauged. For

example, most of the heavy equipment utilized on the North Slope is manufactured in the

contiguous 48-states or overseas. Therefore, there won't be any direct manufacturing

employment generated on the North Slope as a result of a North Slope firm investing in one of

these assets. Those impacts will occur where the product is manufactured. On the other hand,

employment in the NSB may be generated as a result of transportation and wholesale activities

associated with a heavy equipment purchase. Once these direct impacts have been estimated,

they can be used in an I-O model of the NSB to estimate the secondary impacts.

The regional purchase coefficients are based upon information gathered during the contractor

interviews, internet searches to identify production locations for brand name equipment and

secondary data sources such as the Survey of Manufactures, and professional judgment. 

Appendix Table A-4 presents the regional purchase coefficients used for E&D assets used on

Alaska's North Slope.

7.6 ASSIGNMENT OF EXPENDITURES TO IMPLAN SECTORS

At this point, capital expenditure estimates by asset and activity unit have been divided into

production and margin categories and allocated to geographic regions. Each asset and margin

was then assigned to an IMPLAN sector. In Appendix A, Table A-5 shows the concordance

between the assets and IMPLAN sectors. 
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7.7 CAPITAL EXPENDITURES BY IMPLAN SECTOR AND REGION

Capital expenditures were then summed across IMPLAN sectors to produce the matrix shown in 

Table A-6 in Appendix A. These values are later combined with expenditures on labor,

materials and purchased services to produce the final vectors used in the model (See Appendix

B).
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8. MATERIAL INPUTS

Most major material inputs such as fuel were estimated based on information on cost and

quantity gathered in the industry interviews or based on the expert engineering knowledge of

project staff. Separate sections of this chapter provide summaries of the quantities, prices and

total costs of various groups of material purchases including:

• Equipment Fuel Use

• Camp Material Uses

• Well Drilling Materials

• Gravel Island Materials

• Production Module Installation Materials

• Production Island Operation

• Pipeline Construction Materials

• Materials for Land Base Operations

8.1 OVERVIEW OF MATERIAL PURCHASES

In order to determine what materials and purchased services are utilized in quantities that are

significant enough to warrant estimation, data from the latest national-level input-output table of

the U.S. economy was tabulated and analyzed. The latest table available is for the year 1992, as 

developed by the Bureau of Economic Analysis, and published in September 1998. This

tabulation was presented earlier in Exhibit 6-1.

As shown in Exhibit 6-1 and discussed in Chapter 6, the various activities that comprise the oil

and gas industry are subsumed within four sectors in the national I-O table. The largest of these 

sectors is mining Sector 8.0001, Crude Petroleum and Natural Gas. The three smaller sectors are 

all construction industries. These include Sector 11.0601 (Petroleum and Natural Gas Well

Drilling), Sector 11.0602 (Petroleum, Natural Gas, and Solid Mineral Exploration), and Sector

12.0215 (Maintenance and Repair of Petroleum and Natural Gas Wells).

Of these four sectors, the mining sector, Crude Petroleum and Natural Gas, is far larger than the 

others with output of over $100 billion compared to just over $10 billion for Petroleum and

Natural Gas Well Drilling and between $1 and $2 billion for the other two sectors.

Exhibit 6-1 provides the dollars of purchases for all input sectors that accounted for at least one

half of one percent of industry output for any of the four sectors. In total, there were 53 sectors

that met this criterion. Note that as shown at the bottom of Exhibit 6-1, the purchases from these 

53 sectors account for 96 to 99 percent of the total purchases of the four oil and gas sectors. The 

other sectors, which combined accounted for only one to four percent of intermediate purchases, 

were considered too small to be relevant to the analysis. 
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Many of the 53 sectors listed in Exhibit 6-1 were not producers of materials. They include

purchases of services, trade margins, payments of taxes and capital type purchases. These

purchases are discussed in Chapters 6, 7 and 9. 

Of the remaining sectors, nine, which happen to be the first nine sectors listed in Exhibit 6-1, 

were considered to be material inputs. These include the following sectors:

• 27.0100 Industrial inorganic and organic chemicals

• 27.0406 Chemicals and chemical preparations, not elsewhere classified

• 29.0203 Polishes and sanitation goods

• 31.0101 Petroleum refining

• 31.0102 Lubricating oils and greases

• 31.0200 Asphalt paving mixtures and blocks

• 36.0100 Cement, hydraulic

• 36.1100 Concrete products, except block and brick

• 36.1900 Minerals, ground or treated

In summary, material inputs to the oil and gas production process are made up of four main types 

of commodities. The first, represented by the first three sectors on the list, are chemicals. The

second, corresponding to the fourth and fifth sectors on the list are the products of petroleum

refining such as gasoline as well as lubricating oils and greases. The third, corresponding to the 

sixth through eighth sectors on the list, are the various paving and building compounds, asphalt,

concrete and cement. The fourth and final group of major material inputs, corresponding to the

final sector on the list, is specialty minerals used in well drilling operations.

The type of products for each of these sectors and their associated SIC codes were useful input to 

the interviewing process. Estimates were solicited on the usage of these various inputs for the

particular activity under consideration. These estimates were often based on usage rates for

particular pieces of equipment that were then multiplied by the number of units in use, the hours

or days of use per piece of equipment and the cost per unit of the input. An example would be

the gallons of fuel used per day for a pickup truck. This estimate would then be multiplied by

the product of the number of pickup trucks and the number of days they were employed in the

task. Total usage would then be multiplied by the cost of fuel. Since the products were already

defined by SIC code and input-output sector it was a simple matter to code them to IMPLAN

sector. As the estimates were in purchasers prices, rough estimates of shipping costs by mode

and wholesale and retail margins (if applicable) had to be made prior to assignment to sectors. 

Finally, the area of production for each of the inputs was specified, so that the resulting values

could be divided among the local community, the KPB, Anchorage, and the 49 States.
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8.2 EQUIPMENT FUEL USE

Fuel use by vehicle or equipment type was estimated by multiplying daily, or in the case of

helicopters hourly, fuel use estimates by the numbers of each type of vehicle and the number of

days required for the task they are engaged in. Estimates of the types and numbers of equipment 

are provided in the engineering description. Estimates of daily fuel use per piece of equipment

are based on a combination of engineering staff expertise and interviews. A listing of the

number of pieces of equipment, hours used, daily or hourly fuel use, and total gallons consumed 

is provided in Exhibit 8-1.

Fuel cost was then derived by multiplying by a price of $1.50 per gallon, which was developed

based on the industry interviews. This is the price for diesel fuel and gasoline produced by the

Phillips crude oil topping plant located at Prudhoe Bay. One-third of this cost is assumed to be

for local truck transportation. The final dollar cost estimates are provided in Exhibit 8-1

In some cases, the information collected in the industry interviews was further adjusted or

enhanced by expert staff. Discussions of these adjustments for particular activities are discussed 

in the following paragraphs.

Seismic Survey

The only major material purchase for seismic surveys is the consumption of fuel for vehicle and 

arctic camp use. Fuel use estimates were provided in the interviews as a daily range for the

entire operation. Although information was provided on the cost of flying in fuel from

Fairbanks, it is assumed that all fuel is trucked in from Prudhoe Bay, as this is a far more

common practice. The midrange of the daily estimates was used and multiplied by 30 to convert 

to a monthly estimate.

North Slope Support

Fuel use for equipment in this activity was developed as part of a more specific procedure and is 

discussed in Section 8.2, below.

General Personnel Transport

Fuel use for this activity was based on the numbers of pieces of equipment and engineering

estimates of fuel use per day. Detailed data on these pieces of equipment are provided in the

engineering descriptions for this activity and are summarized in Exhibit 8-1.
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Ice Road and Ice Island Construction

Fuel use for these activities was based on the numbers of pieces of equipment and engineering

estimates of fuel use per day. Detailed data on these pieces of equipment are provided in the

engineering descriptions for these activities and are summarized in Exhibit 8-1.
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Daily Total

Days Fuel Fuel Fuel Transport

Equipment Type Number Used Use Use Cost Cost

All 30 4,050 121,500 $121,500 $60,750

Bus 1 1 40 40 $40 $20

Van 3 1 30 90 $90 $45

Total 130 $130 $65

Small Grader 1 26 30 780 $780 $390

Snow Blower 1 26 60 1,560 $1,560 $780

Small Rollagons 6 22 30 3,960 $3,960 $1,980

100-bbl Water Truck 2 68 60 8,160 $8,160 $4,080

300-bbl Water Truck 1 34 60 2,040 $2,040 $1,020

Ice Mill 1 16 150 2,400 $2,400 $1,200

Ice Mill Loader/Grader 1 16 150 2,400 $2,400 $1,200

Loader 1 16 150 2,400 $2,400 $1,200

Dump Truck 4 64 60 15,360 $15,360 $7,680

Large Grader 1 156 150 23,400 $23,400 $11,700

Heavy Duty Pick-up 9 72 30 19,440 $19,440 $9,720

Survival Shed Generator 1 25 150 3,750 $3,750 $1,875

Total 85,650 $85,650 $42,825

Small Grader 1 4 30 120 $120 $60

Snow Blower 1 2 60 120 $120 $60

Small Rollagons 6 12 30 2,160 $2,160 $1,080

100-bbl Water Truck 2 80 60 9,600 $9,600 $4,800

300-bbl Water Truck 1 40 60 2,400 $2,400 $1,200

Ice Mill 1 20 150 3,000 $3,000 $1,500

Ice Mill Loader/Grader 1 20 150 3,000 $3,000 $1,500

Loader 1 20 150 3,000 $3,000 $1,500

Dump Truck 4 80 60 19,200 $19,200 $9,600

Large Grader 1 60 150 9,000 $9,000 $4,500

Heavy Duty Pick-up 9 72 30 19,440 $19,440 $9,720

Survival Shed Generator 1 25 150 3,750 $3,750 $1,875

Total 74,790 $74,790 $37,395

Drill Ship 1 1 8,640 8,640 $8,640 $4,320

Ice Breaker 1 1 12,960 12,960 $12,960 $6,480

Work Boat 3 1 4,320 12,960 $12,960 $6,480

Fuel Barge 1 1 4,320 4,320 $4,320 $2,160

Ocean Going Tug 1 1 8,640 8,640 $8,640 $4,320

Total 47,520 $47,520 $23,760

Drill Ship 1 1 2,160 2,160 $2,160 $1,080

Fuel Barge 1 1 1,080 1,080 $1,080 $540

Total 3,240 $3,240 $1,620

Drill Ship 1 1 4,320 4,320 $4,320 $2,160

Ice Breaker 1 1 6,480 6,480 $6,480 $3,240

Work Boat 3 1 2,160 6,480 $6,480 $3,240

Fuel Barge 1 1 2,160 2,160 $2,160 $1,080

Ocean Going Tug 1 1 4,320 4,320 $4,320 $2,160

Total 23,760 $23,760 $11,880

Fuel Barge 1 1 1080 1,080 $1,080 $540

Total 1,080 $1,080 $540

1. Geological Survey (One Month)

2. General Personnel Transport (One Day)

Exhibit 8-1: Estimates of Fuel Consumption by Activity

4. Ice Road Construction (Ten Miles)

5. Ice Island Construction (Per Island)

6. Move Drill Ship or Bottom Founded Structure (One Day)

7. Operate Drill Ship in Calm Waters (One Day)

8. Operate Drill Ship in Rough Waters (One Day)

9. Operate Mobile Exploration Platform (One Day)
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Daily Total

Days Fuel Fuel Fuel Transport

Equipment Type Number Used Use Use Cost Cost

Helicopter 1 4.5 hours 100/hour 450 $450 $225

All Equipment 1 96 96 $96 $48

Cat Loader 1/3 1 150 50 $50 $25

Total 146 $146 $73

Drill Rig 1 90 1128 101,520 $101,520 $50,760

Front-end loader 1 90 150 13,500 $13,500 $6,750

Forklift 1 90 150 13,500 $13,500 $6,750

Heavy Duty Pick-up 2 90 30 5,400 $5,400 $2,700

Total 133,920 $133,920 $66,960

Drill Rig 1 25 1128 28,200 $28,200 $14,100

Front-end loader 1 25 150 3,750 $3,750 $1,875

Forklift 1 25 150 3,750 $3,750 $1,875

Heavy Duty Pick-up 2 25 30 1,500 $1,500 $750

Total 37,200 $37,200 $18,600

Drill Rig 1 4 648 2,592 $2,592 $1,296

Gravel Mining

 Large Cats 3 60 200 36,000 $36,000 $18,000

 Small Cats 2 60 150 18,000 $18,000 $9,000

Gravel Placing

 Large Cats 3 60 200 36,000 $36,000 $18,000

 Small Cats 2 60 150 18,000 $18,000 $9,000

 Large Graders 2 60 150 18,000 $18,000 $9,000

 Compactors 2 60 150 18,000 $18,000 $9,000

Gravel Hauling

 Trucks 16 60 90 86,400 $86,400 $43,200

230,400 $230,400 $115,200

Concrete Work

 Cranes 2 90 240 43,200 $43,200 $21,600

 Small Cats 2 90 150 27,000 $27,000 $13,500

 Back Hoes 2 90 240 43,200 $43,200 $21,600

 Cement Trucks 2 45 90 8,100 $8,100 $4,050

 Heavy Duty Pick-up 8 120 30 28,800 $28,800 $14,400

Fabric Placement

 Cranes 1 30 240 7,200 $7,200 $3,600

 Small Cats 1 30 150 4,500 $4,500 $2,250

 Heavy Duty Pick-up 2 30 30 1,800 $1,800 $900

Sheet Piling

 Cranes 1 90 240 21,600 $21,600 $10,800

 Hammer 1 90 600 54,000 $54,000 $27,000

 Small Cats 1 90 150 13,500 $13,500 $6,750

 Drilling Machines 2 90 192 34,560 $34,560 $17,280

 Hot Water Truck 1 90 90 8,100 $8,100 $4,050

 Heavy Duty Pick-up 2 90 30 5,400 $5,400 $2,700

 Generator Sets 2 90 120 21,600 $21,600 $10,800

 Mechanics Truck 1 90 30 2,700 $2,700 $1,350

 Welding Machines 2 90 120 21,600 $21,600 $10,800

Total 346,860 346,860 173,430

10. Helicopter Support (One Day)

11. Barge Support (One Day)

12. Drill Exploration Well (One Well)

Exhibit 8-1: Estimates of Fuel Consumption by Activity (continued)

13. Drill Production Well (One Well)

14. Well Workover (One Well)

15. Construct Gravel Production Island (Per Island)

16. Protect Gravel Production Island (Per Island)
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Daily Total

Days Fuel Fuel Fuel Transport

Equipment Type Number Used Use Use Cost Cost

Offloading

 Cranes 3 14 240 10,080 $10,080 $5,040

 Small Cats 2 14 150 4,200 $4,200 $2,100

 Heavy Duty Pick-up 4 14 30 1,680 $1,680 $840

Installation and Hookup

 Cranes 2 120 240 57,600 $57,600 $28,800

 Small Cats 2 120 150 36,000 $36,000 $18,000

 Small Fork Lift 2 120 30 7,200 $7,200 $3,600

 Heavy Duty Pick-up 4 120 30 14,400 $14,400 $7,200

 Welding Machines 8 120 120 115,200 $115,200 $57,600

Total 246,360 $246,360 $123,180

Heavy Duty Pick-up 4 365/4 30 10,950 $10,950 $5,475

Small Cats 2 365/2 150 54,750 $54,750 $27,375

Van 1 365/4 30 2,738 $2,738 $1,369

Cranes 1 365/2 120 21,900 $21,900 $10,950

Generator Sets 1 365 150 54,750 $54,750 $27,375

Production Equipment 1 365 48,000 17,520,000 $17,520,000 $0

Total 17,665,088 $17,665,088 $72,544

Offloading

 Cranes 1 7 240 1,680 $1,680 $840

 Small Cats 1 7 150 1,050 $1,050 $525

 Heavy Duty Pick-up 2 7 30 420 $420 $210

Installation and Hookup

 Cranes 1 21 240 5,040 $5,040 $2,520

 Small Cats 1 21 150 3,150 $3,150 $1,575

 Small Fork Lift 1 21 30 630 $630 $315

 Heavy Duty Pick-up 2 21 30 1,260 $1,260 $630

 Welding Machines 2 21 120 5,040 $5,040 $2,520

Total 18,270 $18,270 $9,135

Heavy Duty Pick-up 1 365/4 30 2,738 $2,738 $1,369

Total 2,738 $2,738 $1,369

Ditch Witch 3 75 120 27,000 $27,000 $13,500

Thumb Hoe 1 75 216 16,200 $16,200 $8,100

Small Cats 11 75 150 123,750 $123,750 $61,875

Modified Backhoe Trencher 2 75 240 36,000 $36,000 $18,000

Spoils Truck 2 75 90 13,500 $13,500 $6,750

Generator 1 75 288 21,600 $21,600 $10,800

Heavy Duty Pick-up 7 75 30 15,750 $15,750 $7,875

Total 253,800 $253,800 $126,900

Texoma Drill 1 75 168 12,600 $12,600 $6,300

Small Cats 8 75 150 90,000 $90,000 $45,000

Concrete Slurry Truck 1 75 90 6,750 $6,750 $3,375

Generator 1 75 288 21,600 $21,600 $10,800

Heavy Duty Pick-up 6 75 30 13,500 $13,500 $6,750

Total 144,450 $144,450 $72,225

22. Onshore Pipeline Construction (10 Miles)

19. Onshore Gas Production Installation (Per Facility)

20. Gas Production Facility Operation (Per Year)

17. Production Module Installation (Per Island)

18. Production Island Operation (Per Year)

21. Offshore Pipeline Construction (10 Miles)

Exhibit 8-1: Estimates of Fuel Consumption by Activity (continued)
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Daily Total

Days Fuel Fuel Fuel Transport

Equipment Type Number Used Use Use Cost Cost

Lay Pipe

 Tug Boats (for Lay Barges) 4 33 4320 570,240 $570,240 $285,120

 Dive Boats 2 33 960 63,360 $63,360 $31,680

 Cranes 2 33 240 15,840 $15,840 $7,920

 Loader Cats 1 33 150 4,950 $4,950 $2,475

 Side Boom Cats 4 33 150 19,800 $19,800 $9,900

 Heavy Duty Pick-up 2 33 30 1,980 $1,980 $990

 Welding Trucks 2 33 30 1,980 $1,980 $990

Concrete Work

 Cranes 2 84 240 40,320 $40,320 $20,160

 Small Cats 2 102 150 30,600 $30,600 $15,300

 Back Hoes 2 69 240 33,120 $33,120 $16,560

 Cement Trucks 2 87 90 15,660 $15,660 $7,830

 Heavy Duty Pick-up 8 59 30 14,160 $14,160 $7,080

812,010 $812,010 $406,005

Small Cats 16 365 150 876,000 $876,000 $438,000

Single-unit Flatbed 12 365 60 262,800 $262,800 $131,400

Combination Flatbed 8 365 90 262,800 $262,800 $131,400

Forklift 22 365 30 240,900 $240,900 $120,450

Heavy Duty Pick-up 40 365 30 438,000 $438,000 $219,000

Total 2,080,500 $2,080,500 $1,040,250

River Boat 8 34 66 17,952 $17,952 $8,976

Ocean Boat 2 34 90 6,120 $6,120 $3,060

Air Boat 2 34 120 8,160 $8,160 $4,080

Total 32,232 $32,232 $16,116

Install/Remove Production Modules 1 n.a. 246,360 246,360 $246,360 $123,180

Well Workover/Removal 30 n.a. 2,592 77,760 $77,760 $38,880

Total 324,120 $324,120 $162,060

26. Abandon Island

24. Land Base Operation

25. Spill Containment (Per Year)

23. Sea Floor Pipeline Construction (10 Miles)

Exhibit 8-1: Estimates of Fuel Consumption by Activity (continued)

Drill Ships and Mobile Exploration Platforms

As discussed in the engineering description for this set of activities, fuel consumption for the full 

group of vessels was estimated at 1.6 million gallons of fuel for 30 days under power. Fuel

consumption for the workboats was estimated at 180 gallons per hour based on data collected for 

the sub-arctic model. Fuel for the other vessels was estimated based on vessel size. The

estimates were double the work boat rate for the drill ship, sea-going tug and fuel barge and the

triple the rate for the ice breaker. The resulting fuel use roughly equals the original estimate of

1.6 million gallons. These fuel use rates were also assumed to vary based on the activity as the

amount of time under power would also vary. Fuel use for rough seas operations were assumed

to be half of the use when underway. Calm seas use was assumed to be a quarter. Estimates for 

each activity were then developed by multiplying fuel use for the vessels used in the activity and 

the daily fuel use estimate. The results are provided in Exhibit 8-1.
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Helicopter Support

The only major material purchase for helicopter support is the consumption of fuel for the

helicopter. Fuel use estimates were provided in terms of use per hour and multiplied by hours of 

operation. According to the interviews, the helicopter consumes 100 gallons per hour. Project

engineering staff estimates three trips per day at 1.5 hours round trip or 4.5 hours. Fuel use is,

therefore, assumed to be 450 gallons per day.

Barge Support

The only major material purchase for barge support is the consumption of fuel for the onboard

motors and the cat. Fuel use estimates were provided in terms of use per hour and multiplied by

hours of operation. The two power units use diesel fuel at the rate of 3 gallons per hour each or 6 

gallons in total. The barges are assumed to be in motion 12 to 16 hours a day. At 16 hours per

day, which would cover some lesser fuel use while not in motion, fuel use would be 96 gallons

per day. 

Well Drilling

Equipment fuel use in the well drilling sectors includes estimates for the drill rig itself along with 

miscellaneous equipment including a loader, a forklift and two pickups. The estimated fuel use

is based upon the assumed number of days of duration for the task and the fuel use per piece of

equipment. The drill rig is assumed to use 1128 gallons of fuel per day. For well workovers,

none of the miscellaneous equipment is required.

Gravel Island Construction, Protection and Equipment Installation

Fuel use for these activities was based on the numbers of pieces of equipment and engineering

estimates of fuel use per day. Detailed data on these pieces of equipment are provided in the

engineering descriptions for these activities and are summarized in Exhibit 8-1.

Production Island Operation

While vehicles used on the island are available 365 days per year the number of days for the

island vehicles was adjusted downward by two to four times to account for the small size of the

island and the intermittent use of the equipment.

Also shown are expenditures for natural gas to power the generators, compressors and pumps

that are part of the modules installed on the island. On average, it is estimated that $48,000 per 

day of natural gas will be consumed. While the figure is shown in the above table, we have

eliminated it from the vectors used in the model. As noted in Chapter 4, the expenditure is based 

on an oil industry accounting practice. Based upon the results from two other approaches that

we used to corroborate the figure, it is assumed that the expenditure includes both labor and

capital used for gas extraction/processing. Note that such costs are already included in our
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estimates of labor and capital for this activity. In addition, the value of the raw material itself is

assumed to be negligible since it is primarily a by-product that is readily available from oil

production activities.

Pipeline Construction

Fuel use for these activities was based on the numbers of pieces of equipment and engineering

estimates of fuel use per day. Detailed data on these pieces of equipment are provided in the

engineering descriptions for these activities and are summarized in Exhibit 8-1.

Gas Production Facilities

Fuel use for these facilities were based on scaled down version of the estimates for the

production facility installation and operation. They were based on a rule of thumb that the

facility would cost roughly one-sixteenth the cost of the full facility.

Land Base

Fuel use for this activity is based on the numbers of pieces of equipment, and engineering

estimates of fuel use per day. Detailed data on these pieces of equipment are provided in the

engineering descriptions for this activity and are summarized in Exhibit 8-1.

Spill Containment

The only major material purchase for the spill co-op is the consumption of fuel for vehicle and

arctic camp use. Fuel use estimates were provided in the interviews as a daily range per hour of 

boat usage and was converted to yearly estimates based on estimates of the number of trips per

week, the operating season for each type of craft and the length of each trip in hours.

Abandon Island 

Fuel use estimates for abandoning a production island were based on the assumption that

removing the production equipment would entail the same fuel use as installing the equipment

and that shutting down each of an assumed 30 wells would require the same time and fuel use as 

a well workover.

8.3 MATERIAL USES AT EMPLOYEE CAMPS AND QUARTERS

A number of materials are required at the employee hotel/camps and at the employee quarters on 

the production island. The development of these estimates is described in the following two

subsections.
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North Slope Support Camps

There are a number of major material purchases for the North Slope support activity. These

materials are detailed in the engineering task description for this activity and include food and

laundry as well as fuel, chemicals, filters and other inputs to the electric generators and water and 

sewer systems. 

Developing the final estimates for materials required four steps. First, estimates on a per person

per day basis were converted to daily basis using an average occupancy of 80 percent or 240

persons. Second, each of the estimates was assigned to an IMPLAN sector. In some cases the

estimate had to be further divided prior to coding by IMPLAN sector. Third, the purchases were 

divided once again to separate the margins from the actual cost of the good. Finally, each

estimate was divided yet again by geographic area.

Items that were further divided included estimates for food, housekeeping supplies, generator

inputs, and water system chemicals. Food was divided based on PCE food purchases in the

NSB. Housekeeping supplies were divided equally among soaps, polishes, surface active agents 

and toilet preparations. Miscellaneous generator inputs were divided equally between oil

(petroleum products), antifreeze (chemicals preparations n.e.c.), and other. As the only

information on other inputs is that it includes rags, these costs were assigned to textile goods

n.e.c. Two-thirds of water system chemicals were assigned to chorine (alkalies & chlorine) and

one-third to iodine (inorganic chemicals n.e.c.). Sewerage chemicals were assigned to biological 

products which are part of the drug sector in the IMPLAN model. The costs for electricity for

water and sewer treatment were dropped as the cost of generation is already covered. The

remaining assignments are reasonably self-evident.

Due to the lack of detailed data a few simplifying assumptions were used in separating the cost

of the actual good from transportation margins. First, only transportation margins were

estimated with no allocation to wholesale trade. Since some of the largest purchases are for

North Slope produced petroleum products the inaccuracies caused by this assumption are less

important. A second assumption is that all of the transportation margins are assigned to truck

transportation. Since, most of the goods would almost certainly move by truck, especially the

movements from Southern Alaska and the intra-North Slope petroleum movements; this

assumption will also cause minimal distortion. Finally, it is assumed that either one-third or one 

half of movements were assigned to transportation. The one-third assumption for petroleum 

products is based on data, provided through the interviews, that fuel on the North Slope is priced 

at cost $1.50 per gallon with one-third of that cost for transportation. The assumptions for other

goods are based on the general expertise of project staff.

Divisions among areas were based on the expertise of project staff. Consumption of North Slope 

petroleum products was straight forward. Goods that were likely to be at least partially produced 

in the Other Alaska area were assigned 50 percent to Other Alaska and 50 percent to other U.S. 

This included food and housekeeping supplies. All other goods were assigned to other U.S.
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including chemicals, filters and other generator inputs. The total dollar cost of these items, the

amount attributable to margins and the purchase location for each of these items is provided in

Exhibit 8-2.

EXHIBIT 8-2: MATERIAL CONSUMPTION ESTIMATES FOR A 300 PERSON HOTEL/CAMP

Description Days 

Used

Cost 

Per Day

Annual 

Cost

NSB 

Purchases

Other AK 

Purchases

Other US 

Purchases

IMPLAN 

Sector

Food 365 1920 $700,800 $350,400 $350,400 PCE Dist.

Truck Transport (For Food) 365 960 $350,400 $87,600 $175,200 $87,600 435

Laundry 365 90 $32,850 $32,850 464

Soaps (Supplies) 365 7.5 $2,738 $1,369 $1,369 196

Polishes (Supplies) 365 7.5 $2,738 $1,369 $1,369 197

Surface Actives (Supplies) 365 7.5 $2,738 $1,369 $1,369 198

Toilet Preparations (Supplies) 365 7.5 $2,738 $1,369 $1,369 199

Truck Transport (For Laundry etc.) 365 120 $43,800 $19,163 $21,901 $2,738 435

Diesel Fuel (For Generator) 365 2400 $876,000 $876,000 210

Truck Transport (For Diesel Fuel) 365 1200 $438,000 $438,000 435

Oil (For Generator) 365 300 $109,500 $109,500 210

Truck Transport (For Oil) 365 100 $36,500 $36,500 435

Antifreeze/Cleanup (For Generator) 365 200 $73,000 $73,000 209

Truck Transport (For Antifreeze etc.) 365 200 $73,000 $18,250 $36,500 $18,250 435

Other Inputs (For Generator) 365 200 $73,000 $73,000 123

Truck Transport (For Rags) 365 200 $73,000 $18,250 $36,500 $18,250 435

Truck Transport (For Water System) 365 350 $127,750 $127,750 435

Chlorine (For Water System) 365 50 $18,250 $18,250 186

Iodine (For Water System) 365 25 $9,125 $9,125 189

Truck Transport (For Chemicals) 365 75 $27,375 $6,844 $13,687 $6,844 435

Filters (For Water System) 365 50 $18,250 $18,250 338

Truck Transport (For Filters) 365 50 $18,250 $4,563 $9,125 $4,563 435

Chemicals (For Sewage System) 365 50 $18,250 $18,250 195

Truck Transport (For Chemicals) 365 50 $18,250 $4,563 $9,125 $4,563 435

Total $3,146,302
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Other Camp Operations

There are three major categories of material purchases for the production island operation

activity. These purchases and their associated quantities and costs, which are discussed in detail

in the engineering description, include: (1) food and housekeeping supplies; (2) miscellaneous

materials and supplies; and (3) fuel.

The costs for food laundry and housekeeping supplies for camp-like quarters in other activities

were taken directly from the hotel/camp and adjusted to reflect the smaller number of personnel.

The camp has a capacity of 300, but on average is assumed to be 80 percent full and thus serve

240 persons. The production island is estimated to have 62 full time staff members, but it is

assumed that additional personnel will require food and lodging on a short-term basis. These

include employees conducting well workovers, non-production staff such as engineers and

draftsman, and consultants and other experts brought in for specific duties. It is estimated that an 

additional ten personnel will be staying on the island at any one time raising total average

occupancy to 72 persons or 30 percent of that for the hotel/camp. The estimates for the hotel

camp were therefore multiplied by 30 percent to derive estimates for the production island. The

numbers of employees used for each of the activities using camp operations are provided in

Exhibit 8-3.

EXHIBIT 8-3: NUMBER OF EMPLOYEES USED TO ESTIMATE FOOD AND 

HOUSEKEEPING SUPPLIES

Activity Number of Employees

1. Geological Survey 100

3. North Slope Support Camp 240

6. Move Drill Ship or Bottom Founded Structure 116

7. Operate Drill Ship in Calm Waters 25

8. Operate Drill Ship in Rough Waters 116

9. Operate Mobile Exploration Platform 24

18. Production Island Operation 72

8.4 WELL DRILLING MATERIALS

There are three major categories of material purchases for the well drilling activities. These

purchases, which are discussed in detail above in the engineering description, include: (1) the

casing, tubing and wellhead; (2) the drilling fluids, muds, and cements; and (3) the fuel.

Estimates of the costs of each of these components, as collected from industry interviews, were

provided in the engineering description. The casing, tubing and wellhead are expected to cost
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approximately $32,000 per day for a production well or a total of $960,000. Of this total,

$50,000 is for the wellhead and the remainder is for casing and tubing. To distribute these costs 

to production, transportation and wholesale margins, it was necessary to make some assumptions 

about the average well depth (13,000 feet) as well as the weight and cost of the casing and tubing 

used. The casing was assumed to weigh 40 pounds per foot and cost $8.00 per foot f.o.b. plant. 

The tubing was assumed to weigh 10 pounds per foot and to cost $4.75 per foot f.o.b. plant. It

was assumed that each well would need 13,000 feet of casing and 52,000 feet of tubing (four

strings): i.e., 520,000 pounds of casing and 520,000 pounds of tubing. Transportation costs are

based upon an average freight rate of $0.45 per pound. Pipe is sourced from the 48 contiguous

states, Canada, and Japan.

The production and margin costs were then assigned to appropriate IMPLAN sectors. Exhibit 8-

4 provides these estimates separately for wellhead, casing, and tubing.

Exploration and production wells are assumed to have the identical costs for these items. 

However, no wellhead, casing or tubing is assumed for well workovers, although there is some

evidence that workovers occasionally require a small amount of repair to casing or even more

rarely to the tubing.

The drilling fluids, muds and cements are estimated to cost $3,500 per day or $315,000 for a

exploration well, and $105,000 for a production well. Each of these estimates was in delivered

prices, so wholesale and transportation margins had to be divided out and assigned to the

Expenditures by Margins for Casing, Tubing and Well Head

North

IMPLAN Slope Other Other

Commodity Sector Description Burrough Alaska US Foreign Total

Casing Total 13,473 148,204 106,940 106,940 375,556

258 Steel Pipe and Tubes - - 52,015 52,015 104,029

433 Railroads and Related Services - 38,316 11,384 11,384 61,084

435 Motor Freight Transportation 8,422 48,034 11,384 11,384 79,224

436 Water Transportation 1,296 46,832 22,768 22,768 93,664

447 Wholesale Trade 3,756 15,022 9,389 9,389 37,556

Tubing Total 15,065 154,621 182,379 182,379 534,444

258 Steel Pipe and Tubes - - 123,457 123,457 246,913

433 Railroads and Related Services - 38,333 11,390 11,390 61,114

435 Motor Freight Transportation 8,424 48,053 11,390 11,390 79,258

436 Water Transportation 1,296 46,857 22,781 22,781 93,715

447 Wholesale Trade 5,344 21,378 13,361 13,361 53,444

Well Head Total 1,422 9,203 29,219 10,156 50,000

313 Oil Field Machinery - - 26,250 8,750 35,000

433 Railroads and Related Services - 2,656 586 195 3,438

435 Motor Freight Transportation 1,016 3,828 586 195 5,625

436 Water Transportation 156 1,719 1,172 391 3,438

447 Wholesale Trade 250 1,000 625 625 2,500

TOTAL 29,960 312,028 318,537 299,475 960,000

Exhibit 8-4
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 152 Arctic IMPAK

appropriate sectors. These margins were developed in aggregate assuming these were mostly

lower value goods such as mud and cement moved in break bulk.

The remaining manufacturing costs were disaggregated among IMPLAN sectors using data on

the relative purchases of these items by the well drilling sector as calculated from the 1992 BEA 

I-O table as shown in Exhibit 8-5.

BEA BEA

11.0601 12.0215

Construction: Construction:

Petroleum Maintenance

& Natural and Repair

Gas of Petroleum

BEA I-O Well Exploration Production & Natural Well

Industry IMPLAN Drilling Well Well Gas Wells Workover

Number BEA I-O Industry Name Sector ($, Millions) ($) ($) ($, Millions) ($)

27.0100 Industrial inorganic and organic chemicals 189 394 136,180 45,393 25 2,880

27.0406 Chemicals and chemical preparations, n.e.c. 209 62 21,429 7,143 4 461

29.0203 Polishes and sanitation goods 198 0 - - 27 3,111

31.0102 Lubricating oils and greases 213 81 27,996 9,332 0 -

31.0200 Asphalt paving mixtures and blocks 211 0 - - 23 2,650

36.0100 Cement, hydraulic 232 88 30,416 10,139 33 3,802

36.1100 Concrete products, except block and brick 243 0 - - 14 1,613

36.1900 Minerals, ground or treated 250 108 37,329 12,443 3 346

Total 733 253,350 84,450 129 14,862

Exhibit 8-5: Selected Oil and Gas Industry Input Data From the 1992 BEA Input-Output Table

For well maintenance, the relative costs of these materials over the life of the well were

estimated by comparing the sum of the dollar purchases for these inputs between the well drilling 

and well maintenance sectors in the 1992 BEA I-O table. This ratio was applied to the estimates 

for production wells to estimate the costs for these inputs for well maintenance for the life of a

well.

This result was then divided by three to approximate the cost of these inputs for a single

workover. This factor of three is based on an estimate of a twenty year well lifetime and a

workover every five years. Workovers therefore are assumed to occur after the fifth, tenth and

fifteen year of a wells operation.

This per workover estimate was then disaggregated among IMPLAN sectors using data on the

relative purchases of these inputs by the well maintenance sector as calculated from the 1992

BEA I-O table.

The final step was to estimate margins on the well workover inputs, which was accomplished by

assuming the same ratio of margins to manufacturing cost as for production wells.

The resulting estimates for the manufacturing component are provided in Exhibit 8-5. The final

estimates for margins are provided in Exhibit 8-6.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 153 Arctic IMPAK

North

IMPLAN Slope Other

Activity Sector Description Burrough Alaska Total

Exploration Wells n.a. Manufacturing - 253,350 253,350

435 Motor Freight Transportation 7,538 22,612 30,150

447 Wholesale Trade 7,875 23,625 31,500

Total 15,413 299,587 315,000

Production Wells n.a. Manufacturing - 84,450 84,450

435 Motor Freight Transportation 2,513 7,537 10,050

447 Wholesale Trade 2,625 7,875 10,500

Total 5,138 99,862 105,000

Well Workovers n.a. Manufacturing - 14,862 14,862

435 Motor Freight Transportation 442 1,326 1,769

447 Wholesale Trade 462 1,386 1,848

Total 904 17,575 18,479

Exhibit 8-6: Expenditures by Margins for Drilling Fluids, Mud and Cement

8.5 GRAVEL ISLAND MATERIALS

There are four major categories of material purchases that are consumed in the construction of a 

gravel production island. These purchases, which are discussed in detail above in the

engineering description, include: (1) the components of the concrete blocks; (2) the state

royalties for gravel; (3) the weld rods; (4) the erosion protection fabric; (5) the sheet piling; and

(6) the fuel. Note that there is no cost for the gravel that is mined, however, a $1 per cubic yard 

royalty is paid to the state. The cost of this royalty is included as a material. While strictly

speaking this is not a cost of the material itself, it is considered a material-related cost.

Estimates of the costs of each of these components, as collected from the industry interviews, are 

provided in the engineering description. The costs for each of the components except for fuel are 

summarized in Exhibit 8-7. Information on the inputs to the cement making process was

provided only as a total. This total was divided amongst: (1) the cement and cement additives;

(2) the sand and gravel materials used in the concrete; and (3) the cable and shackles used to join 

the concrete. The proportions were 50 percent to the cement and cement additives and 25

percent to the other two items. These assignments were made based on an examination of the

BEA national-level I-O table.

To distribute the costs for each item amongst production, and transportation and wholesale

margins, it was necessary to make some assumptions about where these items were purchased

and how they were transported to the North Slope and the construction site. The production and 

margin costs were then assigned to the appropriate IMPLAN sectors. The results are provided in 

Exhibit 8-8.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 154 Arctic IMPAK

EXHIBIT 8-7: MATERIAL ESTIMATES FOR GRAVEL PRODUCTION ISLAND CONSTRUCTION

Material Type Number of Units Cost Per Unit Total Cost

CONCRETE COMPONENTS

Cement and cement additives $750,000

Sand, gravel and aggregates $375,000

Cable and Shackles $375,000

Total 7,500 cubic yards $200 per cubic yard 1,500,000

OTHER MATERIALS

State Royalties for Mined Gravel Materials for Island 800,000 cubic yards $1 per cubic yard $800,000

Erosion Protection Fabric 27,000 square yards $0.30 per square yard $81,000

Sheet Piling 3,125,000 pounds $0.45 per pound $1,400,000

Welding Rods 8,640 hours $5 per hour $43,200

TOTAL

Total $3,824,200

8.6 PRODUCTION MODULE INSTALLATION MATERIALS

There are four major categories of material purchases that are consumed in the construction of a 

gravel production island. These purchases, which are discussed in detail above in the

engineering description, include: (1) piping; (2) fittings and valves and other piping related

materials; (3) electrical components and systems, materials and supplies; (4) structural shapes,

siding and roofing, doors and windows; and (5) the fuel.

The cost of all the materials, except fuel, was estimated by engineering staff to be 90 percent of

the $2,600,000 expended for equipment and materials or $2,340,000. The costs for each of the

components except for fuel are summarized in Exhibit 8-9.

To distribute the costs for each item amongst production, and transportation and wholesale

margins, it was necessary to make some assumptions about where these items were purchased

and how they were transported to the North Slope and the construction site. The production and 

margin costs were then assigned to the appropriate IMPLAN sectors. The results are provided in 

Exhibit 8-10.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 155 Arctic IMPAK

EXHIBIT 8-9: MATERIAL ESTIMATES FOR PRODUCTION MODULE INSTALLATION

Material Type Percent of Material Costs Total Cost

Piping 30 percent $702,000

Fittings and valves and other piping related materials 30 percent $702,000

Electrical components and systems, materials and supplies 25 percent $585,000

Structural shapes, siding and roofing, doors and windows 15 percent $351,000

Total $2,340,000

Expenditures for Materials Used in Gravel Island Construction

Commodity Sector Description North Slope Other Alaska Other US Total

Cement Total 61,875 688,125 - 750,000

232 Cement, Hydraulic - 375,000 - 375,000

435 Motor Freight Transportation 61,875 185,625 - 247,500

447 Wholesale Trade - 127,500 - 127,500

Aggregates Total 375,000 - - 375,000

041 Sand and Gravel 187,500 - - 187,500

435 Motor Freight Transportation 187,500 - - 187,500

Cables and Total 7,184 71,726 296,095 375,005

Shackles 256 Steel Wire and Related Products - 10,313 195,938 206,251

433 Railroads and Related Services - 11,331 22,419 33,750

435 Motor Freight Transportation 3,994 11,981 40,275 56,250

436 Water Transportation - 7,500 7,500 15,000

447 Wholesale Trade 3,190 30,601 29,963 63,754

Erosion Total 2,617 19,991 58,393 81,001

Protection 128 Canvas Products - 1,053 20,007 21,060

Fabric 433 Railroads and Related Services - 6,059 11,988 18,047

435 Motor Freight Transportation 1,928 5,783 19,440 27,151

436 Water Transportation - 486 486 972

447 Wholesale Trade 689 6,610 6,472 13,771

Sheet Pilings Total 42,000 322,000 1,036,000 1,400,000

282 Fabricated Structural Metal - - 224,000 224,000

433 Railroads and Related Services - 154,000 308,000 462,000

435 Motor Freight Transportation 42,000 154,000 490,000 686,000

436 Water Transportation - 14,000 14,000 28,000

447 Wholesale Trade - - - -

Welding Rods Total 1,296 9,936 31,968 43,200

266 Nonferrous Rolling and Drawing - - 6,912 6,912

433 Railroads and Related Services - 4,752 9,504 14,256

435 Motor Freight Transportation 1,296 4,752 15,120 21,168

436 Water Transportation - 432 432 864

447 Wholesale Trade - - - -

Exhibit 8-8
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 156 Arctic IMPAK

8.7 PRODUCTION ISLAND OPERATION

As discussed in the engineering description of this task, miscellaneous materials were difficult to 

estimate. As a result, an average of $10,000 per day is assumed, and distributed among items

that could be identified in proportion to rough estimates of their costs. Due to the large number 

of items, the same percentages were used to distribute all delivered values among production

costs, transportation costs and wholesale margins. In total 77 percent of costs are assumed to be 

for production. Five percent of all goods are assumed to be produced in Alaska and the

remainder in the U.S. The production and margin costs were then assigned to the appropriate

IMPLAN sectors. Exhibit 8-11 provides the initial and final estimates of costs for the various

items, the percentages used to divide delivered costs among production and margins, the final

results and the IMPLAN sector assignments.

Expenditures for Materials Used During Installation of Modules to Equip One Production Island

North

IMPLAN Slope Other Other

Commodity Sector Description Burrough Alaska US Foreign Total

Piping and Total 24,570 232,362 936,468 210,600 1,404,000

Related 303 Pipe, Valves, Pipe Fittings - 49,140 737,100 196,560 982,800

Materials 433 Railroads and Related Services - 49,140 49,140 - 98,280

435 Motor Freight Transportation 17,550 52,650 70,200 - 140,400

436 Water Transportation - 14,040 14,040 14,040 42,120

447 Wholesale Trade 7,020 67,392 65,988 - 140,400

Electrical Total 10,238 96,818 390,195 87,750 585,000

Systems 355 Transformers - 2,048 30,713 8,190 40,950

356 Switchgear - 2,048 30,713 8,190 40,950

359 Relays and Industrial Controls - 2,048 30,713 8,190 40,950

360 Electrical Industrial Apparatus, NEC - 2,048 30,713 8,190 40,950

368 Wiring Devices - 10,238 153,563 40,950 204,750

369 Lighting Fixtures and Equipment - 2,048 30,713 8,190 40,950

433 Railroads and Related Services - 20,475 20,475 - 40,950

435 Motor Freight Transportation 7,313 21,938 29,250 - 58,500

436 Water Transportation - 5,850 5,850 5,850 17,550

447 Wholesale Trade 2,925 28,080 27,495 - 58,500

Structural Total 6,143 144,086 197,262 3,510 351,000

Shapes, Siding, 282 Fabricated Structural Metal - 33,415 50,123 - 83,538

Roofing, Doors 283 Metal Doors, Sash, and Trim - 32,432 48,649 - 81,081

and Windows 285 Sheet Metal Work - 32,432 48,649 - 81,081

433 Railroads and Related Services - 12,285 12,285 - 24,570

435 Motor Freight Transportation 4,388 13,163 17,550 - 35,100

436 Water Transportation - 3,510 3,510 3,510 10,530

447 Wholesale Trade 1,755 16,848 16,497 - 35,100

GRAND TOTAL 40,950 473,265 1,523,925 301,860 2,340,000

Exhibit 8-10
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 157 Arctic IMPAK

8.8 PIPELINE CONSTRUCTION MATERIALS

There are seven major categories of material purchases for pipeline construction activities. 

These purchases, which are discussed in detail above in the engineering description, include: (1)

the piping; (2) the shipping for the pipe; the coating for the pipe; (3) the insulation for the pipe;

(4) the cement to hold the VSMs; (5) the anodes; (6) the vertical support members or VSMs; and 

(7) the fuel.

Estimates of the costs of each of these components, as collected from industry interviews, were

provided in the engineering description on a per mile basis. The costs for all of these items

except fuel are summarized in Exhibit 8-12. Note that the costs for cement include expenditures 

for the cement truck and an operator which were already estimated and included in the

manpower and capital estimates. As a result, the estimate for materials was adjusted downward

by one-third to reflect only the purchased materials.

To distribute material costs to production, transportation and wholesale margins, it was necessary 

to make some assumptions about where these items were purchased and how they were

transported to the North Slope and the construction site. The production and margin costs were

then assigned to the appropriate IMPLAN sectors. Exhibit 8-13 provides these estimates

separately for offshore and onshore pipeline construction.

Exhibit 8-11: Miscellaneous Materials and Supplies for Production Island Operation

Rail Truck

Initial Scaled Tranportation Tranportation

Estimate Estimate to AK to AK

IMPLAN of Daily of Yearly

Item Sector Cost Cost AK US NSB AK US AK US US US NSB AK Total

Percentage of Delivered Cost 73.15% 3.85% 0.85% 8.13% 7.99% 1.13% 1.13% 1.13% 1.13% 0.38% 1.13% 100.00%

Glycol 195 500 948 693 36 8 77 76 11 11 11 11 4 11 948

Calcium Hypoclorite 189 50 95 69 4 1 8 8 1 1 1 1 0 1 95

Defoamer 198 50 95 69 4 1 8 8 1 1 1 1 0 1 95

Scale inhibitor 198 100 190 139 7 2 15 15 2 2 2 2 1 2 190

Pipefitings 303 200 379 277 15 3 31 30 4 4 4 4 1 4 379

Valves 303 250 474 347 18 4 39 38 5 5 5 5 2 5 474

Pipe 258 100 190 139 7 2 15 15 2 2 2 2 1 2 190

Oil filters 313 1,500 2,844 2,080 109 24 231 227 32 32 32 32 11 32 2,844

Oil & grease 198 1,500 2,844 2,080 109 24 231 227 32 32 32 32 11 32 2,844

Halon 209 50 95 69 4 1 8 8 1 1 1 1 0 1 95

Tools 276 100 190 139 7 2 15 15 2 2 2 2 1 2 190

Presssure/temperature guages 403 200 379 277 15 3 31 30 4 4 4 4 1 4 379

Rags 123 100 190 139 7 2 15 15 2 2 2 2 1 2 190

light bulbs 367 25 47 35 2 0 4 4 1 1 1 1 0 1 47

Washers & other fittings 289 25 47 35 2 0 4 4 1 1 1 1 0 1 47

Small household appliances 364 25 47 35 2 0 4 4 1 1 1 1 0 1 47

Bearings & bushings 333 500 948 693 36 8 77 76 11 11 11 11 4 11 948

Total 5,275 10,000 7,315 385 85 813 799 113 113 113 113 38 113 10,000

Truck Transportation

Production Wholesale Trade Within Alaska

Water Transportation

to Alaska
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 158 Arctic IMPAK

EXHIBIT 8-12: MATERIAL ESTIMATES FOR OFFSHORE AND ONSHORE PIPELINE CONSTRUCTION

(PER TEN MILES)

Material Type Number of Sets 3 Cost Per Mile Total Cost

OFFSHORE PIPELINE CONSTRUCTION

Pipe 2 170,000 3,400,000

Shipping 2 126,000 2,520,000

Coating 2 30,000 600,000

Anodes 2 68,000 1,360,000

Total Material Cost 7,880,000

ONSHORE PIPELINE CONSTRUCTION

Pipe 2 170,000 3,400,000

Shipping 2 126,000 2,520,000

Coating 2 30,000 600,000

Insulation 2 35,000 700,000

Cement 1 60,000 600,000

Anodes 2 68,000 1,360,000

Vertical Support Members (VSMs) 1 290,000 2,900,000

Total Material Cost 12,080,000

8.9 MATERIALS FOR LAND BASE OPERATIONS

There are two major categories of material purchases that are consumed in the land base

operation. These purchases, which are discussed in detail above in the engineering description,

include: (1) fuel and other generator inputs; and (2) fuel for vehicle operation.

Estimates of total cost for operation of a set of two diesel generators were described in detail in

the North Slope Support activity, as were the methods used to distribute the costs for each item

amongst production, and transportation and wholesale margins, by geographic area. The

estimates from that activity are simply multiplied by the number of generator sets for this activity 

(eight) to develop the required estimates. The results are provided in Exhibit 8-14.

 

3 One pipe is used for oil and one pipe is used for gas
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 159 Arctic IMPAK

Exhibit 8-13

Expenditures for Materials Used in 10 miles of Pipeline Construction

North

IMPLAN Slope Other Other

Commodity Sector Description Burrough Alaska US Foreign Total

Offshore Pipeline Construction

Pipe Total 98,900 1,413,500 3,604,100 803,500 5,920,000

258 Steel Pipe and Tubes - - 2,116,500 705,500 2,822,000

433 Railroads and Related Services - 280,000 490,000 - 770,000

435 Motor Freight Transportation 70,000 210,000 490,000 - 770,000

436 Water Transportation - 490,000 392,000 98,000 980,000

447 Wholesale Trade 28,900 433,500 115,600 - 578,000

Cathodic Total 25,000 274,000 846,100 214,900 1,360,000

Protection 331 Special Industry Machinery, NEC - 49,000 735,000 196,000 980,000

433 Railroads and Related Services - - 23,700 6,300 30,000

435 Motor Freight Transportation 15,000 45,000 23,700 6,300 90,000

436 Water Transportation - 30,000 23,700 6,300 60,000

447 Wholesale Trade 10,000 150,000 40,000 - 200,000

Wrapping Total 6,350 106,900 388,575 98,175 600,000

220 Miscellaneous Plastic Products - 24,150 362,250 96,600 483,000

433 Railroads and Related Services - - 1,975 525 2,500

435 Motor Freight Transportation 1,250 3,750 1,975 525 7,500

436 Water Transportation - 2,500 1,975 525 5,000

447 Wholesale Trade 5,100 76,500 20,400 - 102,000

Onshore Pipeline Construction

Pipe Total 98,900 1,413,500 3,604,100 803,500 5,920,000

258 Steel Pipe and Tubes - - 2,116,500 705,500 2,822,000

433 Railroads and Related Services - 280,000 490,000 - 770,000

435 Motor Freight Transportation 70,000 210,000 490,000 - 770,000

436 Water Transportation - 490,000 392,000 98,000 980,000

447 Wholesale Trade 28,900 433,500 115,600 - 578,000

VSM Total 370,000 2,930,000 200,000 - 3,500,000

282 Fabricated Structural Metal - 2,220,000 - - 2,220,000

41 Sand and Gravel 200,000 - - - 200,000

232 Cement, Hydraulic - 100,000 100,000 - 200,000

435 Motor Freight Transportation 145,000 235,000 - - 380,000

447 Wholesale Trade 25,000 375,000 100,000 - 500,000

Cathodic Total 25,000 274,000 846,100 214,900 1,360,000

Protection 331 Special Industry Machinery, NEC - 49,000 735,000 196,000 980,000

433 Railroads and Related Services - - 23,700 6,300 30,000

435 Motor Freight Transportation 15,000 45,000 23,700 6,300 90,000

436 Water Transportation - 30,000 23,700 6,300 60,000

447 Wholesale Trade 10,000 150,000 40,000 - 200,000

Wrapping Total 6,350 106,900 388,575 98,175 600,000

220 Miscellaneous Plastic Products - 24,150 362,250 96,600 483,000

433 Railroads and Related Services - - 1,975 525 2,500

435 Motor Freight Transportation 1,250 3,750 1,975 525 7,500

436 Water Transportation - 2,500 1,975 525 5,000

447 Wholesale Trade 5,100 76,500 20,400 - 102,000

Insulation Total 7,200 123,800 454,225 114,775 700,000

249 Asbestos Products - 28,300 424,500 113,200 566,000

433 Railroads and Related Services - - 1,975 525 2,500

435 Motor Freight Transportation 1,250 3,750 1,975 525 7,500

436 Water Transportation - 2,500 1,975 525 5,000

447 Wholesale Trade 5,950 89,250 23,800 - 119,000
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 160 Arctic IMPAK

Exhibit 8-14: Material Consumption Estimates For Generators at Land Base Operations

Description Days 

Used

Cost 

Per 

Day

Number 

of 

Generator 

Sets

Annual Cost NSB 

Purchases

Other AK 

Purchases

Other US 

Purchases

IMPLAN 

Sector

Diesel Fuel (Generator) 365 2,400 8 $7,008,000 $7,008,000 210

Truck Transport (Diesel Fuel) 365 1,200 8 $3,504,000 $3,504,000 435

Oil (Generator) 365 300 8 $876,000 $876,000 210

Truck Transport (Oil) 365 100 8 $292,000 $292,000 435

Antifreeze/Cleanup 

(Generator)

365 200 8 $584,000 $584,000 209

Truck Transport (Antifreeze) 365 200 8 $584,000 $146,000 $292,000 $146,000 435

Other Inputs (Generator) 365 200 8 $584,000 $584,000 123

Truck Transport (Other inputs) 365 200 8 $584,000 $146,000 $292,000 $146,000 435

Total $14,016,000 $11,972,000 $584,000 $1,460,000

8.10 DRILL SHIPS AND MOBILE BOTTOM FOUNDED STRUCTURES

For these activities, materials other than fuel were divided into two categories: boat operations

and E&D operations. For boat operations, each large vessel involved in the activity was

assumed to consume $150 per day of materials. This estimate is based on IMPLAN data for

Alaska's water transportation sector: specifically the ratio between materials and fuel purchases. 

This ratio was multiplied by average fuel consumption per day to estimate expenditures on

materials. Note average fuel consumption per day depends upon the number of vessels involved 

in the activity. Exhibit 8-15 below shows the allocation of intermediate expenditures for vessel

operations. For E&D operations, it was assumed that the activities would require the same type 

of materials needed to operate a production island (excluding well drilling operations which are

addressed separately). These expenditures, shown above in Exhibit 8-11, were first scaled to a

daily basis.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 161 Arctic IMPAK

Activity Description IMPLAN NSB Other AK Other US Foreign Total

Daily Purchases Maintenance and Repair Other Facilities 056 10.00 1.77 0.00 0.00 11.77

Per Vessel Cordage and Twine 122 0.00 0.00 6.02 2.58 8.59

Canvas Products 128 0.00 4.00 11.30 2.69 17.99

Fabricated Rubber Products, N.E.C. 219 0.00 0.39 14.29 4.63 19.31

Hardware, N.E.C. 278 0.00 0.00 7.81 2.60 10.41

Miscellaneous Fabricated Wire Products 304 0.00 0.00 11.03 2.42 13.45

Pumps and Compressors 332 0.00 0.00 5.60 2.40 8.00

Boat Building and Repairing 393 4.48 13.45 0.00 0.00 17.93

Wholesale Trade 447 2.95 8.98 7.46 1.50 20.89

Service Stations 451 8.34 0.00 0.00 0.00 8.34

Miscellaneous Repair Shops 482 9.99 3.33 0.00 0.00 13.32

Total 35.76 31.91 63.50 18.83 150.00

Move Drill Ship or Maintenance and Repair Other Facilities 056 40.00 7.07 0.00 0.00 47.07

Mobile Bottom Cordage and Twine 122 0.00 0.00 24.07 10.31 34.38

Founded Structure Canvas Products 128 0.00 16.00 45.19 10.76 71.95

Fabricated Rubber Products, N.E.C. 219 0.00 1.54 57.16 18.54 77.24

Hardware, N.E.C. 278 0.00 0.00 31.24 10.41 41.65

Miscellaneous Fabricated Wire Products 304 0.00 0.00 44.12 9.68 53.80

Pumps and Compressors 332 0.00 0.00 22.39 9.60 31.99

Boat Building and Repairing 393 17.92 53.80 0.00 0.00 71.72

Wholesale Trade 447 11.80 35.92 29.82 6.01 83.55

Service Stations 451 33.34 0.00 0.00 0.00 33.34

Miscellaneous Repair Shops 482 39.97 13.32 0.00 0.00 53.30

Total 143.04 127.66 253.98 75.31 599.99

Operate Drill Ship Maintenance and Repair Other Facilities 056 10.00 1.77 0.00 0.00 11.77

in Calm Waters Cordage and Twine 122 0.00 0.00 6.02 2.58 8.59

Canvas Products 128 0.00 4.00 11.30 2.69 17.99

Fabricated Rubber Products, N.E.C. 219 0.00 0.39 14.29 4.63 19.31

Hardware, N.E.C. 278 0.00 0.00 7.81 2.60 10.41

Miscellaneous Fabricated Wire Products 304 0.00 0.00 11.03 2.42 13.45

Pumps and Compressors 332 0.00 0.00 5.60 2.40 8.00

Boat Building and Repairing 393 4.48 13.45 0.00 0.00 17.93

Wholesale Trade 447 2.95 8.98 7.46 1.50 20.89

Service Stations 451 8.34 0.00 0.00 0.00 8.34

Miscellaneous Repair Shops 482 9.99 3.33 0.00 0.00 13.32

Total 35.76 31.91 63.50 18.83 150.00

Operate Drill Ship Maintenance and Repair Other Facilities 056 40.00 7.07 0.00 0.00 47.07

in Rough Waters Cordage and Twine 122 0.00 0.00 24.07 10.31 34.38

Canvas Products 128 0.00 16.00 45.19 10.76 71.95

Fabricated Rubber Products, N.E.C. 219 0.00 1.54 57.16 18.54 77.24

Hardware, N.E.C. 278 0.00 0.00 31.24 10.41 41.65

Miscellaneous Fabricated Wire Products 304 0.00 0.00 44.12 9.68 53.80

Pumps and Compressors 332 0.00 0.00 22.39 9.60 31.99

Boat Building and Repairing 393 17.92 53.80 0.00 0.00 71.72

Wholesale Trade 447 11.80 35.92 29.82 6.01 83.55

Service Stations 451 33.34 0.00 0.00 0.00 33.34

Miscellaneous Repair Shops 482 39.97 13.32 0.00 0.00 53.30

Total 143.04 127.66 253.98 75.31 599.99

Operate Mobile Maintenance and Repair Other Facilities 056 10.00 1.77 0.00 0.00 11.77

Bottom Founded Cordage and Twine 122 0.00 0.00 6.02 2.58 8.59

Structure Canvas Products 128 0.00 4.00 11.30 2.69 17.99

Fabricated Rubber Products, N.E.C. 219 0.00 0.39 14.29 4.63 19.31

Hardware, N.E.C. 278 0.00 0.00 7.81 2.60 10.41

Miscellaneous Fabricated Wire Products 304 0.00 0.00 11.03 2.42 13.45

Pumps and Compressors 332 0.00 0.00 5.60 2.40 8.00

Boat Building and Repairing 393 4.48 13.45 0.00 0.00 17.93

Wholesale Trade 447 2.95 8.98 7.46 1.50 20.89

Service Stations 451 8.34 0.00 0.00 0.00 8.34

Miscellaneous Repair Shops 482 9.99 3.33 0.00 0.00 13.32

Total 35.76 31.91 63.50 18.83 150.00

Exhibit 8-15: Intermediate Purchases for Vessel Operations
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 162 Arctic IMPAK

8.11 MATERIALS FOR LAYING SEAFLOOR TIE-BACK PIPELINES

There are several categories of non-fuel material purchases need to lay seafloor tie-back 

pipelines. These purchases include piping, welding rods, anodes, coating for the pipe, concrete

structural supports to hold the pipe off the seafloor bottom, and materials used by vessels laying

the pipelines. Costs for several these categories area based upon estimates found in exhibits 8-12 

and 8-13.

Costs for the concrete structural supports are based on the assumptions that one support will be

used every 10 feet and that each support costs $2,400 to fabricate (Three yards per support @

$800 per yard). Total fabrication costs were adjusted downward to eliminate capital and labor

expenses, which are captured elsewhere. The resulting material purchases were then distributed

to IMPLAN sectors using IO coefficients for the concrete products industry.

Costs for materials for vessel operations are based upon the estimates of daily material purchases 

per vessel shown in Exhibit 8-15. To convert these estimates into the costs associated with

laying ten miles of seafloor tie-back pipelines, it was assumed that the operation would entail 5 

vessels that together could place 1800 feet of pipe per day.

Exhibit 8-16 summarizes these material cost expenditures by the different cost categories

mentioned above.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 163 Arctic IMPAK

Expenditures for Non-Fuel Materials Used in Laying Seafloor Tie-back Pipelines

North

IMPLAN Slope Other Other

Commodity Sector Description Burrough Alaska US Foreign Total

Pipe Total 98,900 1,413,500 3,604,100 803,500 5,920,000

258 Steel Pipe and Tubes - - 2,116,500 705,500 2,822,000

433 Railroads and Related Services - 280,000 490,000 - 770,000

435 Motor Freight Transportation 70,000 210,000 490,000 - 770,000

436 Water Transportation - 490,000 392,000 98,000 980,000

447 Wholesale Trade 28,900 433,500 115,600 - 578,000

Weldind Total 549 775 2,000 195 3,519

Rods 266 Nonferrous Rolling and Drawing - - 362 195 558

433 Railroads and Related Services - 209 836 - 1,045

435 Motor Freight Transportation 549 392 627 - 1,568

436 Water Transportation - 174 174 - 348

 - - - - -

Cathodic Total 25,000 274,000 846,100 214,900 1,360,000

Protection 331 Special Industry Machinery, NEC - 49,000 735,000 196,000 980,000

433 Railroads and Related Services - - 23,700 6,300 30,000

435 Motor Freight Transportation 15,000 45,000 23,700 6,300 90,000

436 Water Transportation - 30,000 23,700 6,300 60,000

447 Wholesale Trade 10,000 150,000 40,000 - 200,000

Wrapping Total 6,350 106,900 388,575 98,175 600,000

220 Miscellaneous Plastic Products - 24,150 362,250 96,600 483,000

433 Railroads and Related Services - - 1,975 525 2,500

435 Motor Freight Transportation 1,250 3,750 1,975 525 7,500

436 Water Transportation - 2,500 1,975 525 5,000

447 Wholesale Trade 5,100 76,500 20,400 - 102,000

Concrete Total 2,439,360 1,726,560 - - 4,165,920

Structural 041 Sand and Gravel 823,680 - - - 823,680

Supports 232 Cement, Hydraulic - 1,393,920 - - 1,393,920

435 Motor Freight Transportation 1,615,680 332,640 - - 1,948,320

Vessel Total 5,244 4,680 9,312 2,761 21,997

Operations 056 Maintenance Other Facilities 1,467 259 0 0 1,726

122 Cordage and Twine 0 0 882 378 1,260

128 Canvas Products 0 587 1,657 394 2,638

219 Fabricated Rubber Products, NEC 0 57 2,096 680 2,832

278 Hardware, NEC 0 0 1,145 382 1,527

304 Misc. Fabricated Wire Products 0 0 1,617 355 1,972

332 Pumps and Compressors 0 0 821 352 1,173

393 Boat Building and Repairing 657 1,972 0 0 2,629

447 Wholesale Trade 433 1,317 1,093 220 3,063

451 Service Stations 1,222 0 0 0 1,222

482 Miscellaneous Repair Shops 1,466 489 0 0 1,954

Exhibit 8-16
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 164 Arctic IMPAK

9. GOVERNMENT, TAPS AND LOCAL GAS ACTIVITY VECTORS

In addition to the E&D activities listed in Exhibit 2-4, IMPAK estimates direct economic

impacts associated with government expenditures, transportation of Arctic OCS oil via the

Trans-Alaska Pipeline System (TAPS), and development of gas reservoirs for local consumption. 

 Below, we describe the methods used to develop the cost vectors for these three activities; as

you will see, these are somewhat different than the overall approach that was used to develop the 

other vectors in the model. For information on how IMPAK estimates the activity levels used to 

stimulate the government, TAPS and local gas vectors, see the appropriate sections in 10.3.1.

9.1 GOVERNMENT

Government revenues, as described below in the "Government" section in 10.3.1, are distributed 

to a number of IMPLAN sectors. To carry out the allocation, separate input-output vectors were 

developed for local, state and federal governments. Each cell in the vectors represents a

percentage of the respective total government expenditures. For the most part, it is assumed that 

all expenditures will take place in the region in which the government is located. Finance

expenditures are the exception; these are all assumed to take place in the continental U.S.

regardless of the government entity.

Vectors for state and local government expenditures were developed using data provided by

MMS. The MMS data was developed using location-specific State and local budget data from

the U.S. Census Bureau's Census of Governments and data from the national input-output 

accounts published by the U.S. Bureau of Economic Analysis. Table C provides the commodity

composition of Federal Government consumption and investment expenditures. To minimize the 

number of industries added to the model, we recalibrated the commodity expenditure shares

using 95 percent of the value of commodity purchases. Expenditures in National Income and

Products Accounts (NIPA) industry 82, reflecting government value added, were adjusted for

taxes and savings and assigned to PCE. The proportion of the expenditures assigned to PCE was 

based on data from the Census of Governments and from published budgets of the relevant State 

and local governments.

9.2 TRANS-ALASKA PIPELINE SYSTEM

TAPS expenditures, described below in the TAPS section 10.3.1, are assigned to IMPLAN

sector 438 (Pipelines, Except Natural Gas) and are divided between the North Slope Borough

and Other Alaska. The regional allocation is based on the NSBTAPSPercent parameter, which is 

currently set at 10%. In IMPAK, the cell associated with sector 438 in the TAPS NSB

coefficient vector (on the NSBMatrix worksheet) is set equal to the NSBTAPSPercent

parameter. All other cells in the vector are set equal to zero. In a similar fashion, the cell

associated with sector 438 in the TAPS Other Alaska coefficient vector (on the AKMatrix
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 165 Arctic IMPAK

worksheet) is set equal to the OtherAKTAPSPercent parameter (which is equal to 1 minus the

NSBTAPSPercent parameter). Again, all other cells in the vector are set equal to zero. In the

future, it will be possible to upgrade the model by developing a specific vector for the TAPS. In 

the meantime, it should be noted that all TAPS revenues are assumed to be expended on current

operations: i.e., new and replacement investment expenditures are not captured in the vector.

9.3 LOCAL GAS

Section 10.4 details how IMPAK estimates the total expenditures needed to develop natural gas

reservoirs to supply local Arctic communities. These expenditures are then distributed across a

number of already existing activities in the model and their associated vectors. The assignments 

are first adjusted to take into account differences in scale. 
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 166 Arctic IMPAK

10. MODEL DOCUMENTATION

This chapter provides an overview of the model and describes how to use it to forecast

manpower and expenditures needed to carry out oil exploration and development (E&D)

operations on Alaska's North Slope. 

The main purpose of the model is to forecast the direct manpower and expenditures needed to 

conduct oil exploration and development (E&D) operations on Alaska's North Slope. These first 

round estimates are categorized in such a way that the IMPLAN economic impact model can be

used to estimate the secondary economic repercussions associated with these E&D activities.

IMPAK is organized around a comprehensive set of activities which characterize oil exploration 

and development in the Arctic. These activities are shown in Exhibit 10-1. For each activity, the 

model houses a cost vector of labor and commodity input requirements on a per unit basis. The 

commodities are defined according to IMPLAN’s 1995 commodity/industry sector scheme. 

Costs are provided in 1999 dollars.

Beginning with the 2001 IMPLAN data (expected to be available near the end of the 2003),

IMPLAN’s sectors will be based on the new North American Industry Classification System

(NAICs), a new sectoring scheme to be used for all Federal economic statistics. After that time,

the Arctic IMPAK: First-Step model described in this documentation will remain a valid stand

alone model. However, some adjustments may be necessary to use it to provide inputs to the

IMPAK: Second-Step model files that MMS has developed to estimate employment, personal

income, total value added etc.

The user is required to input some general data that describe a particular E&D scenario being 

evaluated. To make things easy for the user, most of these data can be obtained from MMS’

E&D reports. These reports are prepared by MMS staff and describe any given proposed lease

sale.

The model translates these user inputs into IMPAK activity levels and then multiplies the results 

by the cost vectors described above. The product and primary output of the model is a vector of 

the estimated expenditures by IMPLAN sector. The model produces separate vectors for each

year in the forecast horizon. The model can handle up to 50 years in the forecast horizon.

The model also breaks down and assigns the cost estimates to geographic regions where the

associated economic impacts accrue. Four regions are utilized: the North Slope Borough, the 

NSB native village, the rest of Alaska, and the continental United States. The output is

organized according to these geographic definitions and is presented on separate worksheet tabs

accordingly. 

A broad schematic of the model is presented in Exhibit 10-2.
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DOI-MMS 167 Arctic IMPAK

Exhibit 10-1: IMPAK Activities and Respective Units 

Activity Unit

Seismic Survey 1 Month

Construct Ice Island 1 Island

Move Platform 1 Day

Calm Water Exploration Drill Ship 1 Day

Rough Water Exploration Drill Ship 1 Day

Drill Exploration Well 1 Well

MBFS for Exploration 1 Day

Place Gravel (Gravel Island) 786,000 cubic yards

Protect Gravel (Gravel Island) 1 Island

Purchase MBFS for Production Total Cost Per Unit

Equip Production Island 1 Island

Drill l Production Well 1 Well

Operate Production Island 1 Island Per Year

Lay Offshore Pipeline 10 Miles

Lay Onshore Pipeline 10 Miles

Lay Seafloor Tie-back Pipeline 10 Miles

Perform Well Work-over 1 Well

Land-base Operations 1 Year

Spill Contingency Operations Annual Cost Per Ten Platforms

Abandonment 1 Island

Construct Ice Roads 10 Miles

Helicopter Support 1 Day

Barge Support 1 Trip

General Personnel Transport 1 Day

Camp Support 1 Year
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 168 Arctic IMPAK

Exhibit 10-2

Broad Schematic of Arctic IMPAK Model

Transposed

Input

Parameters

Secondary

Drivers

NSB Oil

Industry 

Output

NSB Native 

Village 

Output

NSB Nat

Village

Matrix

Alaska

Matrix

User

Input

Model

Input

Alaska

Output

US

Output

NSB Oil

Industry

Matrix

US

Matrix
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 169 Arctic IMPAK

10.1 INSTALLATION

The application consists of an Excel spreadsheet file with supporting documentation activated

through hyperlinks to PDF files. In order for the hyperlinks to work properly, the documentation 

and spreadsheet files should be copied to the same directory. The links will not work with

shortcuts. The list of files that should be copied include:

Arctic_IMPAK.xls (MS Excel spreadsheet application)

IMPAK Model Description.pdf (model documentation)

Arctic IMPAK Final Report.pdf (final report)

Arctic IMPAK Journal Article.pdf (journal article)

To maintain the documentation in a different directory, use Excel's Properties option to set the

default address for hyperlinks in the file:

1.) On the File menu, click Properties. 

2.) Click the Summary tab. 

3.) In the Hyperlink base box, type the path you want to use. 

When opening the file, the user may be prompted with a caution and a choice about enabling the 

macros contained in the file. The application will not work properly if the macros are disabled.

Whether or not the user sees the message will depend upon the security level set for macros in

the user's version of Excel (see the Security Level tab in the Security dialog box (Tools menu,

Macro submenu). Under all settings, if antivirus software that works with Microsoft Office XP

is installed and the file contains macros, the file is scanned for known viruses before it is opened.

 For information on how to change the security settings and/or verify trusted file sources using

digital signatures, see Excel's help files on the topic.
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DOI-MMS 170 Arctic IMPAK

10.2 USER INTERFACE

IMPAK is a Microsoft Excel workbook consisting of numerous worksheets or pages. Most of

these pages are designated by labeled tabs at the bottom of the screen and which the user can

select with the mouse. The main screens are described in more detail below.

10.2.1 Documentation Screen

This screen contains hyperlinks to this help file, the final report, and a journal article about

IMPAK presented at the 24th Annual International Association for Energy Economics

International Conference and 2002 National IMPLAN User's Conference. These files are in PDF 

file format so the user must have a version of Adobe's Acrobat Reader in order to view the files.

10.2.2 Model Setup Screen

This screen provides an avenue for altering most of the default settings used in the model. 

Calculation

Under this option the user can choose how formulas in the model are updated when the

user input data and/or parameters are changed.

• Automatic calculation: each time a cell value changes, all other cells linked to 

it through formulas are immediately updated to reflect the new value. With

large spreadsheets, the updating process can be somewhat slow, especially if

the user's computer has limited memory and/or a relatively slow processor.

• Manual calculation: even though linked cell values change, formulas are not

updated until the user presses F9. When the updating process is slow due to

limited computer resources, this option allows the user to minimize the

amount of time spent waiting for formulas to update.

Initialize Forecast Horizon

Here the user specifies the first year in the forecast horizon. The model automatically

replace the default year with whatever is typed in. The user does not have to click on the 

box or highlight the default year before typing the first year scenario. Subsequent years

that are printed on the data entry screen, the output screens, and the manpower graph are

determined by this initial year.
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DOI-MMS 171 Arctic IMPAK

Edit Model Parameters

The options under this label allow the user to modify the parameters used to estimate the

activity levels for a given scenario. Unlike the variable inputs entered by the user on the

Data Entry screen, parameters remain constant throughout the forecasts horizon. Each

parameter can be restored to its original values by clicking the appropriate "Restore

Default" button.

• Barge Support: These parameters are used to estimate the total number of days of

barge support required under the given scenario. 

Parameter Description

Number of Barge Trips to Construct 1 Gravel

Island

This parameter is multiplied by the number of gravel islands

constructed each year to estimate the number of barge-related 

support trips.

Number of Barge Trips to Equip 1 Production

Island

This parameter is multiplied by the number of production islands

equipped each year to estimate the number of barge-related 

support trips.

Number of Barge Trips to Operate 1 Production

Island

This parameter is multiplied by the number of operating

production islands each year to estimate the number of bargerelated support trips.

Number of Barge Trips to Abandon 1 Production 

Island

This parameter is multiplied by the number of production islands

abandoned each year to estimate the number of barge-related 

support trips.

Number of Barge Trips Per Day of Drill Ship

Operations

This parameter is multiplied by the number of days of drill

ship/MFBS operations (rough water + calm water + MBFS for

exploration) to estimate the number of barge related support trips.

Number of Barge Trips to Lay 10 Miles of

Seafloor Pipe.

This parameter is multiplied by the number of 10-mile units of

seafloor pipe laid to estimate the number of barge related support

trips. The default value (53) was calculated by assuming that each 

barge trip could carry 100 concrete supports out of a total of 5280 

needed per 10 miles of pipeline.

Average Miles Per Day Traveled by Barge Total barge trips generated in the scenario are converted to total

barge mileage based upon the distance from base (a user input) 

and the circuitry factor (see below). Total mileage is then

converted into the number of support days by dividing by average 

miles per day.

Adjustment in Miles Added to Straight-line 

Distance

A figure added to the distance from base user input to take into

account the fact that most trips are not "as the crow flies".
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DOI-MMS 172 Arctic IMPAK

• Helicopter Support: These parameters are used to estimate the total number of days of 

helicopter support required under the given scenario. 

Parameter Description

Number of Helicopter Trips Per Month of 

Seismic Survey

This parameter is multiplied by the number of months of seismic 

survey work each year to estimate the number of helicopterrelated support trips.

Number of Helicopter Trips to Construct 1 

Gravel Island

This parameter is multiplied by the number of gravel islands 

constructed each year to estimate the number of helicopter-related 

support trips.

Number of Helicopter Trips to Equip 1 

Production Island

This parameter is multiplied by the number of production islands 

equipped each year to estimate the number of helicopter-related 

support trips.

Number of Helicopter Trips to Operate 1 

Production Island

This parameter is multiplied by the number of operating 

production islands each year to estimate the number of helicopterrelated support trips.

Number of Helicopter Trips to Abandon 1 

Production Island

This parameter is multiplied by the number of production islands 

abandoned each year to estimate the number of helicopter-related 

support trips.

Average Number of Helicopter Trips Per Day The total number of helicopter trips generated in the E&D 

scenario is divided by this parameter to estimate the number of 

days of helicopter support required.

Daily Fixed Cost for Helicopter Service This cost is added to a variable cost calculation to estimate the 

total cost for 1 day of helicopter support. The variable cost 

estimate is roughly equal to $28.50 per mile (input by the user in 

the average distance from shore column).

Total Daily Cost of Helicopter Service in the 

Base Scenario.

This cost estimated for the base scenario is used in conjunction 

with the total cost estimate for the current scenario (see above) to 

create an adjustment factor which is applied to the total days of 

helicopter support required. The adjustment is necessary to take 

into account differences in the number of islands served in the 

base case and the current scenario.

Number of Helicopter Trips Per Day of Drill 

Ship/MBFS Operations

This parameter is multiplied by the number of days of drill 

ship/MFBS operations (rough water + calm water + MBFS for 

exploration) to estimate the number of helicopter-related support 

trips.

Number of Helicopter Trips to Lay 10 Miles of 

Seafloor Pipe

This parameter is multiplied by the number of 10-mile units of 

seafloor pipe laid to estimate the number of helicopter related 

support trips. The default value (56) was estimated by assuming 

that the typical operation could lay 1880 feet per day and that two 

helicopter trips per day would be needed.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 173 Arctic IMPAK

• Ice Roads: These parameters are used to estimate the miles of ice roads needed to

support the level of activities under the given scenario.

Parameter Description

Adjustment for Doubling Ice Road Depth This parameter is applied to specific portions of the ice road 

network that have to be thicker in order to support the movement 

of heavy equipment. The default factor is based on the 

assumption that associated cost increases are greater than 

proportional increases in thickness.

Factor to Estimate Length of Trunk-line for Ice

Road Network

This parameter (a percentage) is multiplied by the total length of 

the ice road network to estimate the length of the ice road trunk 

line. The length of the trunk line is then subtracted from the total 

length to estimate the mileage attributed to network spurs.

Ice Road Unit Conversion Factor The ice road cost vectors were developed on a "10-mile" basis so 

this factor is used to put the cost vectors and the activity levels on 

a comparable basis.

Ice Road Width Factor for Offshore Pipeline

Construction

Ice roads used to support offshore pipeline construction have to be 

wider than typical ice roads. This factor makes the appropriate 

adjustment where needed.

Adjustment for Building Ice Road Onshore Ice Roads built on shore (e.g., to support the construction of 

onshore pipelines) do not have to be as deep as typical ice roads 

built offshore. This factor makes the appropriate adjustments and 

is based on the assumption that associated cost increases are 

greater than proportional increases in thickness.

• Gravel Island Construction: These parameters are used to estimate the volume (cubic 

yards) of gravel needed to construct the gravel production islands in the scenario. 

These islands are assumed to be truncated pyramids with four sides and rectangularshaped surfaces.

Parameter Description

Width of Gravel Island – First Side The width of one side of the rectangular shaped surface

Width of Gravel Island – Second Side The width of the second side of the rectangular shaped surface

Average Height of Gravel Island Above Water Total volume is first estimated for a complete pyramid based upon 

the slope, height of the pyramid and the width of its sides. The 

top of the pyramid is then truncated and its volume reduced 

accordingly. The parameter is used in both calculations.

Average Width of Island Divided by Height of 

Island (Slope)

Total volume is first estimated for a complete pyramid based upon 

the slope, height of the pyramid and the width of its sides. The 

top of the pyramid is then truncated and its volume reduced 

accordingly. The parameter is used in both calculations.

Percentage of Gravel in Place This parameter is used to reduce the amount of gravel required if 

the scenario calls for the use of an existing gravel island.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 174 Arctic IMPAK

• Underwater Berm: These parameters are used to estimate the volume (cubic yards) of 

gravel needed to construct an underwater gravel berm to support the use of Mobile

Bottom Founded Structures (MBFS). Like the gravel islands, these berms are

assumed to be truncated pyramids with four sides and rectangular-shaped surfaces.

Parameter Description

Width of the Top of the Berm – First Side The width of one side of the rectangular shaped surface

Width of the Top of the Berm – Second Side The width of the second side of the rectangular shaped surface

Maximum Operating Water Depth of MBFS This parameter is subtracted from the water depth value input by 

the user on the Data Entry screen to estimate the height of the 

berm if one is needed. The height is then used to calculate the 

volume of gravel needed.

Average Width of Island Divided by Height of 

Island (Slope)

Total volume is first estimated for a complete pyramid based upon 

the slope, height of the pyramid and the width of its sides. The 

top of the pyramid is then truncated and its volume reduced 

accordingly. The parameter is used in both calculations.
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DOI-MMS 175 Arctic IMPAK

• Platform: These parameters are used to estimate the number of days that drill ships

and MBFS are used for exploration purposes in the scenario. In addition to the

number of days used on site, the screen includes parameters used to estimate the

number of days in transit as well as parameters associated with the completion of subsea wells.

Parameter Description

Average Number of Drill Ship Operating Days 

Per Calm Water Exploration Site

This parameter is multiplied by the Average Number of Drill Ship 

Exploration Sites Per Year to estimate the average annual working 

days per drill ship operating in calm waters in the region.

Average Number of Drill Ship Operating Days 

Per Rough Water Exploration Site

This parameter is multiplied by the Average Number of Drill Ship 

Exploration Sites Per Year to estimate the average annual working 

days per drill ship operating in rough waters in the region.

Average Number of Drill Ship Exploration Sites 

Per Year

This parameter is multiplied by the average number of drill ship 

operating days per exploration site to estimate the average annual 

working days per drill ship operating in the region.

Average Number of MBFS Operating Days Per 

Exploration Site

This parameter is multiplied by the Average Number of MBFS 

Exploration Sites Per Year to estimate the average annual working 

days per MBFS operating in the region.

Average Number of MBFS Exploration Sites Per 

Year

This parameter is multiplied by the average number of MBFS 

operating days per exploration site to estimate the average annual 

working days per MBFS operating in the region.

Average Distance (miles) from Winter Port to 

E&D Region

This parameter is divided by the Drill Ship In-Transit Speed to 

estimate the number of days required to move the rig from its port 

to the region.

Average Distance (miles) from Sub-Sea Well to 

Tie-back Location

This parameter is multiplied by the number of tie-back lines 

required to support the sub-sea wells developed.

Average Number of Drill Ship Operating Days 

Per Sub-Sea Well Completion

This parameter is multiplied by the number of sub-sea well 

completions (entered by the user) to estimate the level of drill ship 

support needed for the operation.

Average Number of Sub-Sea Wells Per Tie-back 

Line

This parameter is divided into the number of sub-sea well 

completions to estimate the number of tie-back pipelines required.

Drill Ship In-Transit Speed (Average Miles Per 

Day)

This parameter is divided into the Average Distance from Winter 

Port to E&D Region to estimate the number of days required to 

move the drill ship from its port to the region.

MFBS In-Transit Speed (Average Miles Per 

Day)

This parameter is divided into the Average Distance from Winter 

Port to E&D Region to estimate the number of days required to 

move the MBFS from its port to the region.

Average Transit Time Between Exploration Sites 

(Days)

This parameter is used in conjunction with the average number of 

exploration sites per year to estimate the number of days spent 

moving rigs between exploration sites.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 176 Arctic IMPAK

• Government Revenue and Taxes: These parameters are used to estimate government

revenues for the local NSB government, the State of Alaska, and the Federal 

government. 

Parameter Description

Royalty Paid to State for Gravel Mining 

Operations

This parameter is multiplied by the volume of gravel mined to 

produce gravel islands and underwater berms; the product is 

added to state government revenues and used to stimulate the 

government vectors in the model.

Royalty Paid for Oil Production This parameter is multiplied by the value of oil production to 

estimate royalty revenues to the Federal government. 

Fee Paid to Lease Land During E&D This parameter is multiplied by leased acreage to estimate acreage 

rental payments to the Federal government. 

Percent of 8(g) Revenues Returned to Alaska This parameter is multiplied by total 8(g) revenues to estimate the 

amounts that contribute to Federal government revenues and state 

government revenues.

Percent of 8(g) Revenues Allocated to General 

Fund

This parameter is used to estimate the amount of the state's 8(g) 

revenues that are allocated to the state's general fund. 

Percent of 8(g) Revenues Allocated to Permanent 

Fund

This parameter is used to estimate the amount of the state's 8(g) 

revenues that are allocated to the Alaska Permanent Fund. 

Percent of AK Tax and 8(g) Revenues 

Distributed to the NSB

This parameter is used to estimate the amount of state government 

revenues that are distributed to the local NSB government.

Percent of Permanent Fund Balance Distributed 

to the Populace

This parameter is used to estimate Permanent Fund dividends that 

can be attributed to the oil industry activity in the given scenario.

Percent of Permanent Fund Dividend Allocated 

to the NSB

This parameter is used to distribute Permanent Fund dividends 

between NSB residents and Other Alaska residents.

Percent of NSB Permanent Fund Dividend Spent 

in the NSB

This parameter is used to determine where NSB residents spend 

their Permanent Fund dividends. The amounts are added to PCE 

estimates in the various regions.

Local Tax Revenues as a Percent of Total Income This parameter is multiplied by the amount of personal income 

generated to estimate the amount of local government revenues 

generated from taxes.

State Tax Revenues as a Percent of Total Income This parameter is multiplied by the amount of personal income 

generated to estimate the amount of state government revenues 

generated from taxes.

Federal Tax Revenues as a Percent of Total 

Income

This parameter is multiplied by the amount of personal income 

generated to estimate the amount of federal government revenues 

generated from taxes.

• Workforce: These parameters are used to estimate the number of native workers who 

are employed in the scenario. 
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 177 Arctic IMPAK

• Other Parameters: These miscellaneous parameters are used to produce a variety of

estimates used in the model.

Parameter Description

Number of Platforms Supported by Each Spill 

Operation

This parameter is used to determine the level of spill containment 

operations required in the given scenario.

Total Camp Expenditures for 1 Camp Operation This parameter is used to determine the level of camp support 

operations required in the given scenario.

Total Daily Expenditures for 1 General Personnel 

Transport (GPT) Operation

This parameter is used to determine the level of GPT operations 

required in the given scenario.

Offshore Pipeline Unit Conversion Factor Expenditure vectors for offshore pipelines were developed on a 

10-mile basis. This parameter converts user input on a one mile 

basis into the appropriate 10-mile units.

Onshore Pipeline Unit Conversion Factor Expenditure vectors for onshore pipelines were developed on a 

10-mile basis. This parameter converts user input on a one mile 

basis into the appropriate 10-mile units.

Percent of TAPS Revenue Distributed to the 

NSB

The parameter is multiplied by total TAPS revenues to estimate 

impacts on the NSB associated with transporting oil from the 

Arctic OCS to Valdez.

PCE as a Percent of Disposable Income This parameter is used to determine the amount of Permanent 

Fund income that is spent on consumption and allocated to PCE.

Personal Savings as a Percent of Total Income This parameter is multiplied by the amount of personal income 

generated to estimate personal savings.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 178 Arctic IMPAK

Review I-O Coefficients

The options under this label allow the user to view the input-output vectors associated

with each IMPAK activity and geographic region. Note that clicking on any one of the

links will bring up all of the vectors for all of the regions; the region selected will be

shown first but the user will then be able to tab to the vectors associated with the other 

geographic areas.

10.2.3 Data Entry

The Data Entry screen presents the user with a table organized by year and E&D activity. 

Shown below in Exhibit 10-3, most of these activities can be obtained from MMS's E&D

Scenario/Schedule. Note that these activities are somewhat different than the ones presented

above in Exhibit 10-1. Through a number of formulas, the data entered by the user are converted 

into quantities that correspond to the activities defined in Exhibit 10-1.

To develop an accurate analysis, the user should enter as much information as possible. The

temporal profile of the data that is entered should also reflect the actual timeline that MMS

expects to see for a given scenario: for example, aggregating the inputs and entering them into a 

single year may lead to anomalous results since many of the formulas have temporal

components.

Once the data has been entered, the user should be able to review the results almost immediately

simply by clicking on the appropriate tab. If calculation is set to "manual", you will need to first 

press F9 so that the formulas are updated; otherwise the results will not correspond to the most

recent data inputs. The password to unprotect the sheet is MMS.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS 179 Arctic IMPAK

Exhibit 10-3: E&D Data Entry Requirements and Respective Units 

Variable Unit

Water Depth (Feet)

Distance from Base (Miles)

Exploration Wells (Number)

Delineation Wells (Number)

Exploration Ice Islands (Number)

Drill Ships for Calm Water Exploration (Number)

Drill Ship for Rough Water Exploration (Number)

Moveable Bottom Founded Structures for 

Exploration

(Number)

Moveable Bottom Founded Structures for 

Production

(Number)

Gravel Production Islands (Number)

Production Wells (Number)

Sub-Sea Production Well Completions (Number)

Offshore Pipeline (Miles)

Onshore Pipeline (Miles)

Landbase Operations4(Proportion of All 

Operations at Local 

Landbase) 

Geo-Survey (Months)

Total Oil Production (MMBLS)

8(g) Oil Production (MMBLS)

Price ($ Per Barrel)

TAPS Surcharge ($ Per Barrel)

Total Lease Acreage (000 Acres)

8(g) Lease Acreage (000 Acres)

Total Bonus Bid (Millions $)

8(g) Bonus Bid (Millions of $)

10.2.4 Output Screens

 

4 Landbase operations entries should be expressed as decimals no greater than 1.0
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DOI-MMS 180 Arctic IMPAK

Output for a scenario is provided in tabular form on four different screens. The NSBOutput

screen presents industry expenditures (by IMPLAN sector) and direct manpower that take place

within and are provided by the NSB oil economy.

The NSBLocalOutput screen displays the impacts that E&D activity has on the local economy in 

the NSB. These impacts include expenditures and employment by the local NSB government,

personal consumption expenditures (PCE) that take place within the NSB, and personal income

that is generated for NSB residents. 

The AKOutput screen presents industry expenditures (by IMPLAN sector), personal

consumption expenditures (PCE), and personal income that is generated or takes within Alaska

but outside of the NSB.

The USOutput screen presents industry expenditures (by IMPLAN sector), personal

consumption expenditures (PCE), and personal income that is generated or takes place in the

continental US. 

Please note that personal consumption expenditures reflect household purchases of commodities

and services in an area and should be used to estimate the induced impacts in a region. The

figures are derived from estimates of disposable income (total income minus taxes and savings)

and take into account differences between where income is earned and where it is spent.

10.2.5 Manpower Graph

The Manpower Graph screen graphically depicts the amount of manpower (days) needed to

conduct the scenario under consideration. The data used to populate the graph are taken from the 

NSBOutput screen and refer to labor directly involved in oil exploration, development and

production activities. Two trends are presented: direct manpower provided by NSB resident

natives and total direct manpower. Management and overhead personnel who are not directly

involved in the activities are not included in the totals. The figures also do not include local

government employment that is stimulated by the E&D activity; these data, however, are

provided at the bottom of the NSBLocalOutput screen.

10.3 MODEL PROCESSING ENGINE

10.3.1 Conversion of Data Entry Input into IMPAK Activity Levels

Since the activities listed in the E&D reports are not identical to those used in IMPAK, the model 

has to convert the E&D data entry input into corresponding IMPAK activity levels. This 

translation takes place in columns AD - DF on the Data Entry worksheet. The conversion is a
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DOI-MMS 181 Arctic IMPAK

function of model equations, model parameters, and Secondary Activity drivers. Details of the

process are provided below.

Geo-Survey: Currently, there are no E&D data that can be used to estimate this activity

level and the user will have to enter the total number of months of geo-surveys required 

for all activities in the E&D scenario.

Construct Ice Island: The number of ice islands constructed is assumed to be equal to the 

number of exploration and delineation rigs entered by the user on the Data Entry screen..

Move Platforms: The level of activity needed to move drill ships and mobile bottom 

founded structures into the E&D region and transition them between sites is driven by the 

corresponding number of vessels entered by the user on the Data Entry screen. The

calculations utilize a number of parameters that can be changed on the PlatformParameter 

screen. These include the distance between the E&D region and the vessel's winter port, 

the average speed of the vessels during transit, and the average number of sites in the

region serviced by each vessel (used to determine the number of moves between sites). 

Drill Ship Exploration in Calm Water: The level of drill ship activity in calm waters 

is based on the number of calm water drill ships entered by the user on the Data Entry

screen. These values are then multiplied by the average annual number of calm water

exploration sites and the average number of working days per site. Both of these

parameters can be changed on the PlatformParameters screen. The resulting product

reflects the total number of working days spent on site. Days spent in transit are

estimated separately below.

Drill Ship Exploration in Rough Water: The level of drill ship activity in rough

waters is based on the number of rough water drill ships entered by the user on the Data

Entry screen. These values are then multiplied by the average annual number of rough

water exploration sites and the average number of working days per site. Both of these

parameters can be changed on the PlatformParameters screen. It is also assumed that a

drill ship is required to drill sub-sea wells. The number of sub-sea wells entered by the

user, therefore, is multiplied by the average number of days required to drill a sub-sea 

well, a parameter that be altered on the PlatformParameters screen. In both cases, the

resulting product reflects the total number of working days spent on site. Days spent in

transit are estimated separately below.

Mobile Bottom Founded Structure (MBFS) for Exploration: The level of MBFS

exploration activity is based on the number of MBFSs used for exploration and entered

by the user on the Data Entry screen. These values are then multiplied by the average

annual number of exploration sites and the average number of working days per site. 

Both of these parameters can be changed on the PlatformParameters screen. The

resulting product reflects the total number of working days spent on site. Days spent in

transit are estimated separately below.
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DOI-MMS 182 Arctic IMPAK

Drill Exploration Well: The number of exploration wells drilled is equal to the

number of exploration and delineation wells entered by the user on the Data Entry screen.

Place Gravel (Island): Due to significant differences in size and the amount of gravel

required, the number of gravel islands is based upon estimates of the volume of gravel

needed support the E&D operations. The model derives these estimates from several data 

fields entered by the user on the Data Entry screen. These include water depth, the

number of gravel production islands, and the number of mobile bottom-founded 

structures. Water depth is used to determine the height of both a gravel island and

underwater berms used to support mobile bottom founded structures.

Expenditures for this activity were developed for a prototype island requiring

approximately 786,000 cubic yards of gravel. It was assumed that the island was situated 

in 40 feet of water, had a surface that was 16 feet above water level, and had sloped sides.

Based upon user input, the model calculates the amount of gravel required to build a

hypothetical island for a given model run. The volume of the hypothetical island(s) is

divided by the volume of the prototype island to produce a scalar which can then be

applied to the cost vector.

The volume of the hypothetical island is a function of several variables which can be

modified by the user. These include the percentage of gravel already in place if an

existing island is used, height of the surface above water level, width and length of the

surface, the slope of the island, and water depth. The first four variables can be modified 

on the parameter screen and are assumed to be the same for all islands constructed in the

scenario. Water depth can be specified for each year on the user input screen.

The user should be aware of several issues in specifying water depths. First, although the 

model does not limit the user-specified water depth, it is unlikely that gravel islands

would be built in depths greater than fifty feet. Second, the relevant E&D input is the

number of production islands in a given year. If more than 1 production island is

constructed in a year, the water depth for that year will reflect the average depth of the

islands. Given that gravel volume increases exponentially with water depth, the

calculation using the average depth will be lower than the value that would be calculated 

using specific water depths for each island. The extent of the difference between the two 

approaches depends upon the variance in the water depths. In cases where the islands are 

constructed in very different water depths, the average approach may significantly

underestimate the volume of gravel needed. Only a minor bias will result when the

islands are constructed in similar depths. 

Protect Gravel Island: The number of gravel islands protected is equal to the number of

production islands plus twenty-five percent of the number of the mobile bottom founded

structures, both entered by the user on the Data Entry screen. The number of mobile
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DOI-MMS 183 Arctic IMPAK

bottom-founded structures is reduced because they don't need the same level of

protection operations as required by the gravel islands.

Mobile Bottom Founded Structure (MBFS) for Production: The level of MBFS

production activity is based on the number of MBFSs used for production and entered by

the user on the Data Entry screen. The treatment of this activity is somewhat different

than MBFSs used for exploration. Because the latter can be re-used over a long period of 

time and in different areas, the MBFS used for exploration is capitalized and an annual

capital cost based on use is assigned to operations. On the other hand, when an MBFS is 

permanently installed for production, it becomes totally dedicated to the scenario; in this

case, therefore, it is treated as purchased equipment and its total cost is assigned to the

project. When the user enters an MBFS for production, the production operations vector 

and the equip production island vector are also stimulated as the costs of these activities 

are assumed to be similar to those associated with production from a gravel island.

Equip Production Island: The number of islands equipped with production modules

is equal to the number of gravel islands and mobile bottom founded structures installed in 

the previous year and entered by the user on the Data Entry screen.

Drill Production Well:The number of production wells drilled is equal to the number of

production wells entered by the user on the Data Entry screen.

Operate Production Island: The number of operating production islands is equal to zero 

if oil production is equal to zero as specified by the user on the Data Entry screen; 

otherwise, it is equal to the total number of islands equipped with production modules

since the inception date (See Equip Production Island above).

Lay Offshore Pipeline: The number of 10 mile pipeline sections is based on the

number of offshore pipeline miles and the number of sub-sea well completions entered by 

the user on the Data Entry screen. The two values are summed and then divided by 10 to 

convert them into the appropriate units. It is assumed that each sub-sea well completion

will require 1 mile of trenched offshore pipe.

Lay Onshore Pipeline:The number of 10 mile pipeline sections is equal to onshore

pipeline miles, entered by the user on the Data Entry screen, divided by 10.

Sea Floor Tie-Back Pipeline: The amount of sea floor pipeline required to connect subsea well completions to existing platforms is driven by the number of sub-sea well

completions in the scenario, which the user must enter on the Data Entry screen. This

value is divided by the average number of wells per tieback line and then converted to an 

integer using a ceiling function: in other words, this conversion results in the number of 

tie-back lines that have to be installed. Finally, the number of lines is multiplied by the

average distance of the line, a parameter on the PlatformParameters screen. It is assumed 
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DOI-MMS 184 Arctic IMPAK

that 1 mile of the total distance between the platform/island is trenched so the average

distance is adjusted accordingly.

Perform Well Workover: The number of well workovers is based on the assumption

that each production well specified on the Data Entry screen will need maintenance every 

6 years.

Landbase Operations: The percent of landbase operations that can be attributed to the

project is based on the corresponding value entered by the user on the Data Entry screen. 

Landbase operations entries should be expressed as decimals no greater than 1.0.

Spill Contingency Operations: The required number of spill contingency response

operations is based on the number of platforms in operation, which the model derives

from the number of production islands entered by the user on the Data Entry screen. To 

be consistent with the expenditure vector, this figure is calibrated by dividing it by the

average number of platforms supported by a spill containment operation.

Abandonment:The number of islands abandoned is derived from the total number of

production islands entered by the user on the Data Entry screen. All islands are assumed 

to be abandoned at the same time.

Construct Ice Roads: The extent of ice roads is derived from several variables entered by 

the user on the Data Entry screen; these include the number of ice exploration islands, the 

number of gravel production islands, and the amount of offshore and onshore pipelines

installed.

To estimate the miles of ice road constructed each year, it was necessary to make some

assumptions about the configuration of the road network. We started by assuming that

the network would consist of 1 main trunk line with spurs leading to the various

operations. We also made two assumptions about the network in the latter years of the

project when only production activities are occurring: (1) the total length of the network

is equal to the total number of offshore pipeline miles, and (2) the trunk line comprises

50% of the total length of the network. By dividing the length of the non-trunk portion of 

the network by the number of production islands, we were then able to estimate the

average length of each spur. We then assumed that the trunk length and average spur

length would remain constant throughout the project.

For each year, the number of activities requiring an ice road is multiplied by the average 

spur length; the result is then added to the length of the trunk line to yield an estimate of 

the total length of the road network. This length is then adjusted to take into account the 

fact that portions of the network will consist of ice roads that are 10 feet thick in contrast 

to the standard ice road which is only 5 feet thick. To make the adjustment, we

quadruple the length of the thicker sections since they cost four times more to build than 

sections of the same length that are standard thickness.
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DOI-MMS 185 Arctic IMPAK

Finally, special ice roads are built to aid in the construction of the pipelines. The roads

used for the offshore pipelines are generally three times wider than normal ice roads so

we multiply their length by 3. The roads built onshore do not have to be as thick as the

standard offshore ice road and are adjusted accordingly.

Helicopter Support: The level of helicopter support required for the scenario is based

upon several variables entered by the user on the Data Entry screen. These include the

average distance from base, water depth (used to determine the scale of gravel placement 

operations), the amount of time spent for geo-surveys, the number of production islands,

the level of oil production, and the number of drill ships and mobile bottom founded

structures.

For each activity requiring helicopter support, we calculate the following product: the

number of helicopter trips per activity unit multiplied by the number of activity units. 

These results are then summed and converted into days of helicopter support. It is

assumed that each helicopter operation makes an average of 3 trips per day.

A final adjustment was made to account for the fact that the average distance/time of a

trip is one determinant of the price of helicopter service. The helicopter expenditure

vector was developed under the assumption that the helicopter would be serving a group

of five islands, situated five miles apart from each other and located approximately

twenty miles from the shore base. As noted earlier, the helicopters make an average of

three trips per day: two sweeps of the islands and a dedicated trip to one of the islands. 

Under these assumptions, it was estimated that helicopter services provide approximately

4.5 hours of support per day.

This daily amount of time is obviously a function of how far the group of islands is

located from the shore base. To develop the function between distance and total daily

service time, we divided the helicopter service time into four components: takeoff/landing time, loading/unloading time, travel time between the islands during sweeps,

and travel time between the shore base and the group of islands. The first three

components are held constant; only the travel time to get to the islands is assumed to vary 

with distance. To estimate that time, we first subtract 1 from the round-trip distance to

remove the effect of landing/takeoff time. Regardless of the distance, we assume that all 

helicopters will travel 0.25 miles at a reduced speed after takeoff and prior to landing. To 

estimate the travel time, we then divide this distance by the average speed which is

assumed to be 100 mph. Finally, the travel time is multiplied by 3 to reflect the three

daily trips that are made.

This travel time variable is then multiplied by $950 to put it on a cost basis. We then add 

this variable cost to fixed cost to compute total daily revenues for helicopter service. 

Fixed cost include the base contract fee ($3,288), taxes ($410), and the fixed hourly
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DOI-MMS 186 Arctic IMPAK

charges ($3,734) such as take-off/landing time, loading/unloading time, and travel time

between the islands during sweeps.

This total cost is then divided by the total helicopter charges for the base scenario

($7,973). We then apply the resulting factor to the estimated days of helicopter service, 

which produces the desired adjustment.

Barge Support: The level of barge support required for the scenario is based upon

several variables entered by the user on the Data Entry screen. These include the average 

distance from base, water depth (used to determine the scale of gravel placement

operations), and the number of production islands, the level of oil production.

For each activity requiring barge support, we calculate the following product: the number 

of barge trips per activity unit multiplied by the number of activity units. The results are 

then summed to compute the total number of barge trips generated by the activities. This 

figure is then multiplied by the average round-trip distance of each trip, yielding total

number of barge miles traveled. Finally, the number of barge miles is divided by the

average barge miles traveled per day to estimate the number of days of barge service

required. It is assumed that barges travel an average of 60 miles per day.

General Personnel Transport: Expenditures for personnel transportation were estimated

for every activity except camp support are therefore based on all of the data entered by

the user on the Data Entry screen. These expenditures, presented on the

"SecondaryDrivers" worksheet, are normalized by the total cost of a personnel

transportation operation, multiplied by the corresponding activity levels, and then

summed. When the sum is multiplied by the personnel transportation input vector, the

result will be the same as if the personnel transportation expenditures had been allocated

to input sectors based upon each commodity's share of the total cost of the transportation

operation.

Camp Support: Expenditures for food and lodging were estimated for every

activity except general personnel transportation and are therefore based on all of the data 

entered by the user on the Data Entry screen. These expenditures, presented on the

"SecondaryDrivers" worksheet, are normalized by the total cost of running a camp,

multiplied by the corresponding activity levels, and then summed. When the sum is

multiplied by the camp support input vector, the result will be the same as if the food and 

lodging expenditures had been allocated to input sectors based upon each commodity's

share of the total cost of a camp operation.

Government

The model uses various government revenue functions to stimulate three government

expenditure vectors: the NSB local government, the Alaska State government, and the US 
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DOI-MMS 187 Arctic IMPAK

Federal government. In all three cases, government expenditures in the current period are 

assumed to be equal to revenues generated in the previous year.

The revenue function for a specific jurisdiction can be modeled by trying to imitate each 

revenue instrument or by using proxies. For many revenue sources, the former approach

would be extremely time-consuming to implement, fraught with the potential of

compounding errors in estimation, and difficult to adapt for changing fiscal regimes. In

addition, the means by which State and local governments obtain revenues will vary over 

time and, certainly, from jurisdiction to jurisdiction. IMPAK instead uses a combination

of the two approaches to estimate revenues resulting from new OCS activities. It directly 

estimates State (and local shares of) revenues from the Federal Government and from

gravel royalties but uses proxies to estimate tax revenues.

State and Local Government

State and local government expenditures are a function of two primary revenue

sources: (1) state and local tax revenues and (2) state revenues obtained from 8(g) 

funds and gravel royalties.

Estimates of tax revenues by jurisdiction are based on ratios of total tax revenues

to total personal income developed from data in the Statistical Abstract of the

United States. To produce the revenue estimates, the ratios are multiplied by the

amount of total personal income generated from the E&D activities in an IMPAK 

scenario. Total Personal Income is used as a proxy for the general level of

economic activity, reflecting changes in infrastructure investment, production,

property assessments, and government tax revenues. By using the relationship

between Total Personal Income and government tax revenues, IMPAK can be

adapted to changing fiscal regimes or for use with other local government entities, 

such as the Northwest Arctic Borough or individual villages. However, given the 

small size of these jurisdictions, and the difficulty of obtaining good data, the user 

should be careful to seek independent confirmation of the revenue estimates.

Neither the State of Alaska nor the NSB has a broad-based income tax or a

general sales tax, so state and local tax revenues are collected through property

taxes, indirect business taxes (IBT), licenses (hunting, motor vehicle, etc.), and

selective sales taxes (alcohol, insurance, motor fuel, and utility). In the NSB,

property taxes represented about 80 percent of NSB operating revenues in FY99. 

The average ratio between total state tax revenues and total personal income in

Alaska was calculated to be 1.6% between 1995 and 1997. The average ratio

between total local tax revenues and total personal income in the state was 

calculated to be 5.17% over the same period. This average local tax ratio was

applied to all Alaska residents. It should be noted that both the state and local tax 

parameters can be changed on the Government Parameters screen.
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OCS oil activities provide income for Alaska residents through worker earnings 

and increases in the annual Permanent Fund dividends. Estimates of local

earnings are obtained by summing, across activities, the product of earnings per

unit and number of units. To estimate PF dividends, the model maintains a

running PF balance based upon annual disbursements and additions generated by

the level of E&D activities specified in the scenario. It should be emphasized that 

IMPAK's PF account only deals with funds related to the scenario under

consideration; its balance and dividends, therefore, do not correspond to the actual 

values associated with the fund itself. Total dividends to Alaska residents are

calculated by multiplying the dividend rate (a parameter) by the balance in the

previous year. A parameter is then used to assign a portion of the total dividends

to NSB residents; the remainder is assigned to Other Alaska residents.

As noted above, revenues are also derived from 8(g) funds. Under section 8(g) of 

the OCS Lands Act, as amended, the Federal Government must pay to the State

27 percent of all revenues (bids to obtain leases, annual lease rental payments, and 

royalties on production) for leases within 3 miles of State waters. In IMPAK,

8(g) revenues are directly estimated based upon projected 8(g) bids, leases and oil 

production. Estimated royalties are the product of the royalty rate (a parameter,)

8(g) oil production, and price per barrel; production and price are both user

inputs. Lease revenues are the product of 8(g) lease acreage (a user input) and the 

acreage rental rate (a parameter). Bonus bids are input by the user. Twenty-seven 

percent of the total 8(g) revenue is then allocated to Alaska, where it is divided

equally between the State budget and the Alaska Permanent Fund. Through the

Government Parameters Worksheet, the user can change the default for any of the 

relevant rates: the Federal royalty rate, the 8(g) payment rate, the percentage of

8(g) revenues going into the Permanent Fund, etc.

The State of Alaska also receives royalties for any sand or gravel mined for E&D 

construction activities on the Arctic OCS. These revenues are estimated directly 

from the projected amounts of sand and gravel needed under a given scenario. 

The current royalty is $1 per cubic yard. This fee is multiplied by the total cubic 

yards of gravel required each year to estimate the total revenues obtained.

The NSB receives none of these payments directly. However, a small portion of

State funds is distributed to the NSB government as intergovernmental revenues. 

The proportion of the revenues going to the NSB (through the State) can be

changed on the Government Parameters Worksheet.

Federal Government

Federal government expenditures are a function of two primary revenue sources:

(1) federal tax revenues generated from earnings, and (2) federal revenues

obtained from royalties, lease revenues, and bonus bids. Government 
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DOI-MMS 189 Arctic IMPAK

expenditures in the current period are assumed to be equal to revenues generated

in the previous year.

Tax revenues are estimated by applying a federal tax rate to earnings that can be

attributed to E&D activities (including government) in the scenario. Earnings are 

obtained by summing, across activities, the product of earnings per unit and

number of units. These results are provided on the USOutput screen. The federal 

tax rate, a parameter, was estimated to be 11.7%. This was calculated as the 

average ratio between 1996 federal individual income tax returns of Alaska

residents and personal income in the state in 1996 (The data were obtained from

the Statistical Abstract of the United States.). Tax revenues were estimated for all 

US residents involved in the scenario. These include production workers directly

involved in the E&D activities as well as overhead support personnel such as oil

company employees serving engineering or administrative functions.

Other Federal revenues were estimated from total royalties, lease rental revenues, 

and bonus (auction) bids, less the portion of these amounts paid to Alaska under

section 8(g) of the OCS Lands Act (see above). Royalties are the product of the

royalty rate (a parameter,) total oil production, and price per barrel; production

and price are both user inputs. Lease revenues are the product of total lease

acreage (a user input) and the acreage rental rate (a parameter). Bonus bids are

input by the user.

Trans-Alaska Pipeline System (TAPS)

It is assumed that TAPS expenditures in a given year are equal to TAPS revenues

generated in the previous year. These revenues are estimated by multiplying total oil

production by a TAPS surcharge which is defined in terms of dollars per barrel. Both

variables are input by the user. It is assumed that all oil produced from the Arctic OCS is 

transported via TAPS to Valdez.

10.3.2 Generation of Model Output

The model inputs are first transposed into a matrix compatible with the regional input-output 

matrices. An Excel array function (transpose) is used to accomplish the task. The transposed

input is then multiplied by each region's input-output matrix to yield the total direct impacts by

region and IMPLAN sector. Again, an Excel array function is used to accomplish the matrix

multiplication (mmult). Note that each year in the forecast horizon requires a separate formula.

It should be noted that annual Permanent Fund (PF) disbursements arising from E&D activities

in the scenario are converted and added to PCE at this time. As noted above, the dividends are 

estimated for both the NSB and "Other Alaska" residents. The disbursements are adjusted for

savings and taxes and then allocated to local spending areas. For example, after the tax and
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DOI-MMS 190 Arctic IMPAK

savings adjustment, PF disbursements to NSB residents are then divided between the North

Slope Borough and Other Alaska. The adjustment for taxes is based upon the tax rate parameters 

found on the Government Parameters worksheet. The PCERate parameter is used to adjust for 

savings and specify the percentage of disposable income assigned to personal consumption

expenditures (PCE). The parameter is currently set at 95% with the remaining 5% going to

savings. A location parameter (NSBPFExpenditurePercent) is used to divide the PCE into the

areas where it is spent. The parameter is currently set at 10%, meaning that NSB residents spend 

10% of their PF dividend, after adjustments for taxes and savings, in the NSB; the remainder is

assumed to be spent in "Other Alaska". Estimated PF expenditures in "Other Alaska" are based 

upon the dividends to all Alaska residents. PF expenditures by "Other Alaska" residents are

assumed to take place entirely in "Other Alaska". Added to these expenditures are purchases by

NSB residents. As implied above, it is assumed that 90% of NSB PF expenditures are made in

"Other Alaska".

10.4 LOCAL GAS PROCESSING

The local gas module is designed to estimate the economic impacts associated with developing

off-shore gas reservoirs for consumption by local communities lining the Hope Basin. The

model is based on a scaled down version of an Arctic oil production scenario and assumes that

development takes place through sub-sea wells bored by drill-ships operating in calm water.

The module utilizes the framework of Arctic IMPAK and provides the same type of parameter

screens, data entry screen, and output screens. Many of the equations and activities are also the

same. Among these are the barge, helicopter and government activities. However, some of the 

activities in Arctic IMPAK are not relevant to the gas scenario and were eliminated; these

include the construction of ice islands and gravel islands, the use of mobile bottom founded

structures for exploration or production, the use of drill ships in rough waters, and the TransAlaska Pipeline System. 

Other activities were borrowed from Arctic IMPAK but were modified in some way to fit the

local gas scenario. In some cases, the estimated activity levels were reduced by 50% to reflect

lower expenditures required to carry out the corresponding operation in the gas scenario. These 

activities include the geo-survey, all well drilling activities, and the construction of on-shore 

pipelines. Expenditures for offshore trenched pipeline, ice road construction, calm water drill

ship operations, and placing of seafloor pipeline were also reduced by 50%; however in these

cases additional modifications were incorporated. Trenched offshore pipeline was limited to 1

mile, with seafloor pipeline constituting any remaining offshore pipeline. Ice roads are only used 

to support pipeline construction. Finally, it is assumed that only 1 drill ship is used for

exploration and the development of the sub-sea wells. 

The assumption of 1 drill-ship also affected the Move Platform activity level; however, the

expenditures were not otherwise reduced since the cost of moving a drill ship in to place should

be fairly similar.
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DOI-MMS 191 Arctic IMPAK

In Arctic IMPAK, the level of spill contingency operations is based on the number of production 

islands. In the gas module, the spill contingency activity level is based on the number of wells

drilled (exploration and sub-sea production well) and drill-ship operating days. Drill ship

operating days is converted into the number of drill-ships required by assuming that they can

operate in the Hope Basin 270 days per year. This value is then scaled by the number of

platforms that can be supported by the spill contingency operation vector developed for Arctic

IMPAK.

In Arctic IMPAK, land base operations for a 25,000 barrel per day island were assumed to

account for 2% of the cost of a $1 billion warehouse operation that supports all E&D activities

on the North Slope. For the gas module, this value was reduced using the following procedure. 

First, we used 1999 historical production data for the North Slope to develop a ratio between gas 

production and oil production of 8.5 billion cubic feet of gas per 1 million barrels of oil

production. Multiplying this ratio by 8.25 million barrels (the annual equivalent of 25,000

barrels per day) results in 70.125 billion cubic feet of gas per year. We then divided this value

into 1.5 billion cubic feet per year (the gas production volumes assumed for the scenario) to

develop a scalar that is then multiplied by the 2% value above.

We utilized the Equip Island vector from Arctic IMPAK as a proxy for the Construct Gas

Production Facility vector, assuming that this would mostly entail equipment installation. The

vector represents the total costs to install all of the oil production equipment on a gravel island. 

To take into account differences in the scale of operations, we developed a total construction cost 

estimate for the gas production facility and then divided that estimate by the total cost of

equipping one gravel island. The remaining percentage is used to stimulate the Equip Island

vector and scales the expenditures appropriately. The construction cost is based upon an 1999

engineering estimate of the cost of developing a Gas-to-Liquid (GTL) plant on the Alaskan 

North Slope5. The cost of a GTL facility designed to handle approximately 180 billion cubic

feet of natural gas per year was estimated at $1.8 billion. This amounts to $10 million dollars per 

1 billion cubic feet of gas processed. This factor is multiplied by the maximum gas production 

volume entered by the user in the model to produce the construction cost estimate.

Finally, we also used the Operation Production Island vector from Arctic IMPAK as a proxy for

the Operation Gas Facility in the local gas module. To take into differences in the scale of

operations, we developed a total operating cost estimate for the gas facility and then divided that

by the total cost of operating an oil production island in the Arctic. The total operating cost

estimate of the gas facility is based on a $2/Mcf gas acquisition price, which is multiplied by gas 

production levels entered by the user on the Data Entry screen.

 

5 Options for Gas-to-Liquids Technology in Alaska, December 1999 (DOE Study DE-AC07-99ID13727). Prepared 

by E.P. Robertson for the U.S. Department of Energy, Office of Fossil Energy, Idaho Operations Office, Idaho City, 

Idaho.
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS Arctic IMPAK

APPENDIX A: CAPITAL TABLES
APPENDIX TABLE A-1

Capital Costs Per Activity Unit† by Asset and Activity

Percent of New Equipment Purchases Used E

Quantity Equipment Percent Total Expected 

IMPLAN Per Purchases Dedication Delivered Cost Life Cost Per Deliver

Activity Asset Sector Activity Unit† that are New to Task (Per Asset) (Years) Activity Unit (Per 

Seismic Survey D7 CAT 311 4 75% 60% 363,000 5 32,670 

 

 Heater 386 4 75% 60% 5,000 5 450 

 

 Insulation 251 4 100% 60% 2,250 5 270 

 

CAT Challenger 311 1 75% 60% 193,000 5 4,343 

 

 Angle Blade 311 1 100% 60% 20,000 5 600 

 

 Heater 386 1 75% 60% 5,000 5 113 

 

 Insulation 251 1 100% 60% 2,250 5 68 

 

966 CAT Loader 311 1 75% 50% 263,000 5 4,931 

 

 Heater 386 1 75% 50% 5,000 5 94 

 

 Insulation 251 1 100% 50% 2,250 5 56 

 

Shaker Truck 312 10 100% 100% 444,000 5 222,000 

 

 Heater 386 10 75% 100% 3,500 5 1,313 

 

 Insulation 251 10 100% 100% 2,250 5 1,125 

 

Nodwell 311 9 75% 100% 222,222 5 75,000 

 

Seismic Equipment 403 1 100% 100% 6,000,000 5 300,000 

 

Survey Equipment 400 1 100% 100% 300,000 5 15,000 

 

60 Foot Sleigh 399 17 60% 100% 25,000 10 6,375 

 

Generator 357 4 90% 100% 150,000 5 27,000 

 

Incinerator 337 1 90% 100% 125,000 7 4,018 

 

Snow Melter 281 1 90% 100% 125,000 7 4,018 

 

500 Gallon Fuel Tank 284 3 100% 100% 2,000 7 214 

 

3000 Gallon Fuel Tank 284 9 100% 100% 10,000 7 3,214 

 

Prefabricated Modules 287 14 100% 100% 60,000 7 30,000 

 

Camp Support Power Generator 357 2 100% 100% 1,205,189 10 241,038 

 

Transformers 355 1 100% 100% 482,076 10 48,208 

 

Switchgear 356 1 100% 100% 482,076 10 48,208 

 

Relays 359 1 100% 100% 482,076 10 48,208 

 

Electrical Apparatus, NEC 360 1 100% 100% 482,076 10 48,208 

 

Wiring Devices 368 1 100% 100% 482,076 10 48,208 

 

Power Facility Construction 050 1 100% 100% 4,820,755 10 482,076 

 

Water Treatment Equipment 349 1 100% 100% 229,560 10 22,956 

 

Water Treatment Construction 050 1 100% 100% 229,560 10 22,956 

 

Sewage Treatment Equipment 349 1 100% 100% 172,170 10 17,217 

 

Sewage Treatment Construction 050 1 100% 100% 172,170 10 17,217 

 

Interest 456 1 100% 100% 6,162,531 10 616,253 

 

Personnel Transport Van 384 3 34% 100% 50,000 9 16 

 

Bus 384 1 34% 100% 75,000 9 8 

 
APPENDIX TABLE A-1

Capital Costs Per Activity Unit† by Asset and Activity

Percent of New Equipment Purchases Used E

Quantity Equipment Percent Total Expected 

IMPLAN Per Purchases Dedication Delivered Cost Life Cost Per Deliver

Activity Asset Sector Activity Unit† that are New to Task (Per Asset) (Years) Activity Unit (Per 

Ice Road Small Rollagon 311 6 60% 63% 39,157 12 7,401 

 

 Heater 386 6 40% 63% 3,267 4 1,235 

 

 Auger 312 6 63% 63% 45,361 12 9,002 

 

 Hydraulic Pump 352 6 53% 63% 30,018 12 5,012 

 

 Insulation 251 6 100% 63% 2,250 6 1,418 

 

Small Grader 311 1 60% 12% 94,554 12 567 

 

 Heater 386 1 40% 12% 3,267 4 39 

 

 Tires 215 1 100% 12% 2,566 6 51 

 

 Motor Vehicle Parts 386 1 60% 12% 8,422 6 101 

 

 Insulation 251 1 100% 12% 2,250 6 45 

 

Snowblower 311 1 60% 35% 150,000 12 2,625 

 

Small Water Truck 317 2 60% 76% 100,000 12 7,600 

 

 100 Barrel Water Tank 284 2 60% 76% 49,916 12 3,794 

 

 Water Pumps 332 2 75% 76% 23,404 6 4,447 

 

 Insulation 251 2 100% 76% 2,250 6 570 

 

Large Water Truck 317 1 57% 76% 138,554 12 5,002 

 

 300 Barrel Water Tank 284 1 60% 76% 110,060 12 4,182 

 

 Water Pumps 332 1 75% 76% 46,807 6 4,447 

 

 Insulation 251 1 100% 76% 4,500 6 570 

 

Ice Mill 311 1 53% 13% 366,054 12 2,102 

 

 Engine 308 1 53% 13% 4 - - 

 Hydraulics 352 1 53% 13% 4 - - 

 Large Grader 311 1 62% 13% 195,181 12 1,311 

 

 Heater 386 1 40% 13% 3,267 4 42 

 

 Insulation 251 1 100% 13% 2,250 6 49 

 

Large Grader 311 1 62% 75% 195,181 12 7,563 

 

 Heater 386 1 40% 75% 3,267 4 245 

 

 Insulation 251 1 100% 75% 2,250 6 281 

 

Large Loader 311 1 60% 8% 175,000 12 656 

 

 Heater 386 1 40% 8% 3,267 4 25 

 

 Insulation 251 1 100% 8% 2,250 6 28 

 

Dump Truck 317 4 60% 30% 96,386 12 5,783 

 

 Heater 386 4 40% 30% 3,267 4 392 

 

 Insulation 251 4 100% 30% 2,250 6 450 

 

Pickup Truck 384 9 58% 25% 25,000 9 3,625 

 

Prefabricated Modules 287 1 100% 21% 30,000 7 900 

 

 Generator 357 1 60% 21% 75,000 12 788 

 

 60 Foot Sleigh 399 1 60% 21% 25,000 10 315 

 
APPENDIX TABLE A-1

Capital Costs Per Activity Unit† by Asset and Activity

Percent of New Equipment Purchases Used E

Quantity Equipment Percent Total Expected 

IMPLAN Per Purchases Dedication Delivered Cost Life Cost Per Deliver

Activity Asset Sector Activity Unit† that are New to Task (Per Asset) (Years) Activity Unit (Per 

Ice Island Small Rollagon 311 6 60% 6% 39,157 12 705 

 

 Heater 386 6 40% 6% 3,267 4 118 

 

 Auger 312 6 63% 6% 45,361 12 857 

 

 Hydraulic Pump 352 6 53% 6% 30,018 12 477 

 

 Insulation 251 6 100% 6% 2,250 6 135 

 

Small Grader 311 1 60% 2% 94,554 12 95 

 

 Heater 386 1 40% 2% 3,267 4 7 

 

 Tires 215 1 100% 2% 2,566 6 9 

 

 Motor Vehicle Parts 386 1 60% 2% 8,422 6 17 

 

 Insulation 251 1 100% 2% 2,250 6 8 

 

Snowblower 311 1 60% 3% 150,000 12 225 

 

Small Water Truck 317 2 60% 89% 100,000 12 8,900 

 

 100 Barrel Water Tank 284 2 60% 89% 49,916 12 4,443 

 

 Water Pumps 332 2 75% 89% 23,404 6 5,207 

 

 Insulation 251 2 100% 89% 2,250 6 668 

 

Large Water Truck 317 1 57% 89% 138,554 12 5,857 

 

 300 Barrel Water Tank 284 1 60% 89% 110,060 12 4,898 

 

 Water Pumps 332 1 75% 89% 46,807 6 5,207 

 

 Insulation 251 1 100% 89% 4,500 6 668 

 

Ice Mill 311 1 53% 17% 366,054 12 2,748 

 

 Engine 308 1 53% 17% 4 - - 

 Hydraulics 352 1 53% 17% 4 - - 

 Large Grader 311 1 62% 17% 195,181 12 1,714 

 

 Heater 386 1 40% 17% 3,267 4 56 

 

 Insulation 251 1 100% 17% 2,250 6 64 

 

Large Grader 311 1 62% 29% 195,181 12 2,924 

 

 Heater 386 1 40% 29% 3,267 4 95 

 

 Insulation 251 1 100% 29% 2,250 6 109 

 

Large Loader 311 1 60% 10% 175,000 12 875 

 

 Heater 386 1 40% 10% 3,267 4 33 

 

 Insulation 251 1 100% 10% 2,250 6 38 

 

Dump Truck 317 4 60% 38% 96,386 12 7,325 

 

 Heater 386 4 40% 38% 3,267 4 497 

 

 Insulation 251 4 100% 38% 2,250 6 570 

 

Pickup Truck 384 9 58% 10% 25,000 9 1,450 

 

Prefabricated Modules 287 1 100% 21% 30,000 7 900 

 

 Generator 357 1 60% 21% 75,000 12 788 

 

 60 Foot Sleigh 399 1 60% 21% 25,000 10 315 

 

Move Platform Fuel Barge 393 1 0% 100% - - - 20

 

Ice Breaker 392 1 0% 100% - - - 162

 

Workboat 392 3 0% 100% - - - 55

 

Tug 392 1 0% 100% - - - 110

 

Drill Ship - Calm Water Drill Ship 392 1 0% 100% - - - 168

 

Fuel Barge 393 1 0% 100% - - - 20

 
APPENDIX TABLE A-1

Capital Costs Per Activity Unit† by Asset and Activity

Percent of New Equipment Purchases Used E

Quantity Equipment Percent Total Expected 

IMPLAN Per Purchases Dedication Delivered Cost Life Cost Per Deliver

Activity Asset Sector Activity Unit† that are New to Task (Per Asset) (Years) Activity Unit (Per 

Drill Ship - Rough Water Drill Ship 392 1 0% 100% - - - 168

 

Fuel Barge 393 1 0% 100% - - - 20

 

Ice Breaker 392 1 0% 100% - - - 162

 

Workboat 392 3 0% 100% - - - 55

 

Tug 392 1 0% 100% - - - 110

 

MBFS - Operate MBFS 392 1 0% 100% - - - 236

 

Fuel Barge 393 1 0% 100% - - - 20

 

Helicopter Support Hellicopter 389 1 20% 100% 5,340,526 15 195 

 

Interest 456 1 20% 100% 4,989,595 15 182 

 

Barge Support Self Propelled Barge 392 1 75% 100% 1,600,000 5 2,000 

 

966 CAT Loader 311 1 75% 35% 263,000 5 115 

 

 Heater 386 1 75% 35% 5,000 5 2 

 

 Insulation 251 1 100% 35% 2,250 5 1 

 

Exploration Well Drill Rig 313 1 20% 100% 30,000,000 15 133,333 2

 

Front-end Loader 311 1 75% 50% 175,000 5 4,375 

 

Forklift 317 1 75% 50% 100,000 5 2,500 

 

Pickup Truck 384 2 75% 35% 25,000 5 875 

 

Production Well Drill Rig 313 1 20% 100% 30,000,000 15 44,444 2

 

Front-end Loader 311 1 75% 50% 175,000 5 1,458 

 

Forklift 317 1 75% 50% 100,000 5 833 

 

Pickup Truck 384 2 75% 35% 25,000 5 292 

 

Well Workover Drill Rig 313 1 20% 100% 7,000,000 8 5,833 

 

Gravel Island (Place Gravel) 988 CAT Loader 311 2 60% 40% 535,000 12 21,400 

 

 Heater 386 2 40% 40% 3,267 4 261 

 

 Insulation 251 2 100% 40% 2,250 6 300 

 

D10 CAT 311 1 60% 40% 735,000 12 14,700 

 

 Heater 386 1 40% 40% 3,267 4 131 

 

 Insulation 251 1 100% 40% 2,250 6 150 

 

966 CAT Loader 311 2 60% 29% 263,000 12 7,627 

 

 Heater 386 2 40% 29% 3,267 4 189 

 

 Insulation 251 2 100% 29% 2,250 6 218 

 

D7 CAT 311 2 60% 29% 363,000 12 10,527 

 

 Heater 386 2 40% 29% 3,267 4 189 

 

 Insulation 251 2 100% 29% 2,250 6 218 

 

Large Grader 311 2 60% 40% 200,000 12 8,000 

 

 Heater 386 2 40% 40% 3,267 4 261 

 

 Insulation 251 2 100% 40% 2,250 6 300 

 

Compactor 311 2 60% 40% 265,000 12 10,600 

 

 Heater 386 2 40% 40% 3,267 4 261 

 

 Insulation 251 2 100% 40% 2,250 6 300 

 

Dump Truck 317 16 60% 40% 200,000 12 64,000 

 

 Heater 386 16 40% 40% 3,267 4 2,091 

 

 Insulation 251 16 100% 40% 2,250 6 2,400 

 
APPENDIX TABLE A-1

Capital Costs Per Activity Unit† by Asset and Activity

Percent of New Equipment Purchases Used E

Quantity Equipment Percent Total Expected 

IMPLAN Per Purchases Dedication Delivered Cost Life Cost Per Deliver

Activity Asset Sector Activity Unit† that are New to Task (Per Asset) (Years) Activity Unit (Per 

Gravel Island (Protect Islandl) Crane 311 2 60% 50% 550,000 12 27,500 

 

 Heater 386 2 40% 50% 3,267 4 327 

 

 Insulation 251 2 100% 50% 2,250 6 375 

 

966 CAT Loader 311 3 60% 43% 263,000 12 16,964 

 

 Heater 386 3 40% 43% 3,267 4 421 

 

 Insulation 251 3 100% 43% 2,250 6 484 

 

Backhoe 311 2 60% 43% 380,000 12 16,340 

 

 Heater 386 2 40% 43% 3,267 4 281 

 

 Insulation 251 2 100% 43% 2,250 6 323 

 

Concrete Truck 317 2 60% 21% 150,000 12 3,150 

 

 Heater 386 2 40% 21% 3,267 4 137 

 

 Insulation 251 2 100% 21% 2,250 6 158 

 

 Insulated Drum 317 2 100% 21% 10,000 12 350 

 

Pickup Truck 384 8 58% 33% 25,000 9 4,253 

 

Crane 311 1 60% 17% 550,000 12 4,675 

 

 Heater 386 1 40% 17% 3,267 4 56 

 

 Insulation 251 1 100% 17% 2,250 6 64 

 

966 CAT Loader 311 1 60% 14% 263,000 12 1,841 

 

 Heater 386 1 40% 14% 3,267 4 46 

 

 Insulation 251 1 100% 14% 2,250 6 53 

 

Pickup Truck 384 2 58% 10% 25,000 9 322 

 

Crane 311 1 60% 50% 400,000 12 10,000 

 

 Heater 386 1 40% 50% 3,267 4 163 

 

 Insulation 251 1 100% 50% 2,250 6 188 

 

Hammer 311 1 57% 75% 210,000 9 9,975 

 

Drilling Machine 312 2 57% 75% 215,000 9 20,425 

 

Pickup Truck 384 2 58% 25% 25,000 9 806 

 

Small Water Truck 317 1 60% 76% 100,000 12 3,800 

 

 100 Barrel Water Tank 284 1 60% 76% 49,916 12 1,897 

 

 Water Pumps 332 1 75% 76% 23,404 6 2,223 

 

 Insulation 251 1 100% 76% 2,250 6 285 

 

 Heater 386 1 40% 76% 3,267 4 248 

 

Van 384 1 57% 25% 50,000 9 792 

 

Welding Machine 324 2 100% 43% 10,000 6 1,433 

 

Generator 357 2 100% 43% 10,000 5 1,720 

 

Cement Mixing Plant 311 1 60% 35% 2,000,000 12 35,000 

 

Pile Driving Template 311 3 100% 35% 15,000 12 1,313 

 
APPENDIX TABLE A-1

Capital Costs Per Activity Unit† by Asset and Activity

Percent of New Equipment Purchases Used E

Quantity Equipment Percent Total Expected 

IMPLAN Per Purchases Dedication Delivered Cost Life Cost Per Deliver

Activity Asset Sector Activity Unit† that are New to Task (Per Asset) (Years) Activity Unit (Per 

Equip Production Island 966 CAT Loader 311 2 60% 7% 263,000 12 1,841 

 

 Heater 386 2 40% 7% 3,267 4 46 

 

 Insulation 251 2 100% 7% 2,250 6 53 

 

966 CAT Loader 311 2 60% 43% 263,000 12 11,309 

 

 Heater 386 2 40% 43% 3,267 4 281 

 

 Insulation 251 2 100% 43% 2,250 6 323 

 

Crane 311 2 60% 8% 550,000 12 4,400 

 

 Heater 386 2 40% 8% 3,267 4 52 

 

 Insulation 251 2 100% 8% 2,250 6 60 

 

Crane 311 1 60% 23% 5,000,000 12 57,500 

 

 Heater 386 1 40% 23% 3,267 4 75 

 

 Insulation 251 1 100% 23% 2,250 6 86 

 

Crane 311 2 60% 50% 550,000 12 27,500 

 

 Heater 386 2 40% 50% 3,267 4 327 

 

 Insulation 251 2 100% 50% 2,250 6 375 

 

Transport Trailer 317 4 60% 23% 135,000 9 33,750 

 

Pickup Truck 384 4 58% 4% 25,000 9 258 

 

Pickup Truck 384 4 58% 25% 25,000 9 1,611 

 

Forklift 317 2 75% 50% 40,000 9 3,333 

 

Welding Machine 324 8 100% 43% 10,000 6 5,733 

 

Rig Mats 282 1 0% 23% - - - 

 

Production Operations 966 CAT Loader 311 2 60% 100% 263,000 12 26,300 

 

 Heater 386 2 40% 100% 3,267 4 653 

 

 Insulation 251 2 100% 100% 2,250 6 750 

 

Pickup Truck 384 4 58% 100% 25,000 9 6,444 

 

Van 384 1 57% 100% 50,000 9 3,167 

 

Crane 311 1 60% 100% 550,000 12 27,500 

 

 Heater 386 1 40% 100% 3,267 4 327 

 

 Insulation 251 1 100% 100% 2,250 6 375 

 
APPENDIX TABLE A-1

Capital Costs Per Activity Unit† by Asset and Activity

Percent of New Equipment Purchases Used E

Quantity Equipment Percent Total Expected 

IMPLAN Per Purchases Dedication Delivered Cost Life Cost Per Deliver

Activity Asset Sector Activity Unit† that are New to Task (Per Asset) (Years) Activity Unit (Per 

Offshore Pipeline Ditch Witch 311 3 60% 35% 200,000 12 10,500 

 

 Heater 386 3 40% 35% 3,267 4 343 

 

 Insulation 251 3 100% 35% 2,250 6 394 

 

Backhoe 311 2 60% 35% 380,000 12 13,300 

 

 Heater 386 2 40% 35% 3,267 4 229 

 

 Insulation 251 2 100% 35% 2,250 6 263 

 

 Long Reach Attachment 311 1 60% 35% 136,000 12 2,380 

 

D7 CAT 311 6 60% 35% 363,000 12 38,115 

 

 Heater 386 6 40% 35% 3,267 4 686 

 

 Insulation 251 6 100% 35% 2,250 6 788 

 

966 CAT Loader 311 3 60% 35% 263,000 12 13,808 

 

 Heater 386 3 40% 35% 3,267 4 343 

 

 Insulation 251 3 100% 35% 2,250 6 394 

 

D6 CAT 311 2 60% 35% 300,000 12 10,500 

 

 Heater 386 2 40% 35% 3,267 4 229 

 

 Insulation 251 2 100% 35% 2,250 6 263 

 

Dump Truck 317 2 60% 35% 150,000 12 5,250 

 

 Heater 386 2 40% 35% 3,267 4 229 

 

 Insulation 251 2 100% 35% 2,250 6 263 

 

Prefabricated Modules 287 2 100% 63% 30,000 7 5,400 

 

60 Foot Sleigh 399 1 60% 63% 25,000 10 945 

 

Generator 357 1 60% 50% 90,000 9 3,000 

 

3000 Gallon Fuel Tank 284 2 100% 35% 10,000 7 1,000 

 

Welding Machine 324 4 100% 35% 105,000 6 24,500 

 

Pipeline Heating Machine 331 2 100% 35% 35,000 6 4,083 

 

Pipeline Coating Machine 331 2 100% 35% 35,000 6 4,083 

 

Industrial Lights 369 2 100% 35% 10,000 6 1,167 

 

Pickup Truck 384 7 58% 10% 25,000 9 1,128 

 

Bridge Section 282 2 0% 35% - - - 

 
APPENDIX TABLE A-1

Capital Costs Per Activity Unit† by Asset and Activity

Percent of New Equipment Purchases Used E

Quantity Equipment Percent Total Expected 

IMPLAN Per Purchases Dedication Delivered Cost Life Cost Per Deliver

Activity Asset Sector Activity Unit† that are New to Task (Per Asset) (Years) Activity Unit (Per 

Onshore Pipeline D7 CAT 311 5 60% 35% 363,000 12 31,763 

 

 Heater 386 5 40% 35% 3,267 4 572 

 

 Insulation 251 5 100% 35% 2,250 6 656 

 

966 CAT Loader 311 2 60% 35% 263,000 12 9,205 

 

 Heater 386 2 40% 35% 3,267 4 229 

 

 Insulation 251 2 100% 35% 2,250 6 263 

 

D6 CAT 311 1 60% 35% 300,000 12 5,250 

 

 Heater 386 1 40% 35% 3,267 4 114 

 

 Insulation 251 1 100% 35% 2,250 6 131 

 

Concrete Truck 317 1 60% 35% 150,000 12 2,625 

 

 Heater 386 1 40% 35% 3,267 4 114 

 

 Insulation 251 1 100% 35% 2,250 6 131 

 

 Insulated Drum 317 1 100% 35% 10,000 12 292 

 

Texoma Drill 312 1 60% 35% 425,000 12 7,438 

 

Prefabricated Modules 287 2 100% 63% 30,000 7 5,400 

 

60 Foot Sleigh 399 1 60% 63% 25,000 10 945 

 

Generator 357 1 60% 50% 90,000 9 3,000 

 

3000 Gallon Fuel Tank 284 2 100% 35% 10,000 7 1,000 

 

Welding Machine 324 2 100% 35% 105,000 6 12,250 

 

Pipeline Heating Machine 331 1 100% 35% 35,000 6 2,042 

 

Pipeline Coating Machine 331 1 100% 35% 35,000 6 2,042 

 

Industrial Lights 369 1 100% 35% 10,000 6 583 

 

Pickup Truck 384 6 58% 10% 25,000 9 967 

 

Sea Floor Pipe Crane 311 2 60% 28% 550,000 12 15,400 

 

 Heater 386 2 40% 28% 3,267 4 183 

 

 Insulation 251 2 100% 28% 2,250 6 210 

 

966 CAT Loader 311 3 60% 23% 263,000 12 9,074 

 

 Heater 386 3 40% 23% 3,267 4 225 

 

 Insulation 251 3 100% 23% 2,250 6 259 

 

Backhoe 311 2 60% 23% 380,000 12 8,740 

 

 Heater 386 2 40% 23% 3,267 4 150 

 

 Insulation 251 2 100% 23% 2,250 6 173 

 

Concrete Truck 317 2 60% 9% 150,000 12 1,350 

 

 Heater 386 2 40% 9% 3,267 4 59 

 

 Insulation 251 2 100% 9% 2,250 6 68 

 

 Insulated Drum 317 2 100% 9% 10,000 12 150 

 

Pickup Truck 384 8 58% 18% 25,000 9 2,320 

 

Cement Mixing Plant 311 1 60% 92% 2,000,000 12 92,000 

 

Tug 392 4 0% 100% - - - 110

 

Dive Boat 393 2 0% 100% - - - 

 
APPENDIX TABLE A-1

Capital Costs Per Activity Unit† by Asset and Activity

Percent of New Equipment Purchases Used E

Quantity Equipment Percent Total Expected 

IMPLAN Per Purchases Dedication Delivered Cost Life Cost Per Deliver

Activity Asset Sector Activity Unit† that are New to Task (Per Asset) (Years) Activity Unit (Per 

Land Base Operations 966 CAT Loader 311 16 60% 100% 263,000 12 210,400 

 

 Heater 386 16 40% 100% 3,267 4 5,227 

 

 Insulation 251 16 100% 100% 2,250 6 6,000 

 

Small Flatbed Truck 384 12 60% 100% 85,000 12 51,000 

 

 Heater 386 12 40% 100% 3,267 4 3,920 

 

 Insulation 251 12 100% 100% 2,250 6 4,500 

 

Truck Tractor 384 8 60% 100% 130,000 12 52,000 

 

 Heater 386 8 40% 100% 3,267 4 2,614 

 

 Insulation 251 8 100% 100% 2,250 6 3,000 

 

Truck Trailer 387 8 60% 100% 32,000 12 12,800 

 

Forklift 317 22 75% 100% 40,000 9 73,333 

 

Pickup Truck 384 40 58% 100% 25,000 9 64,444 

 

Hoists 316 4 60% 100% 250,000 12 50,000 

 

Conveyors 315 4 60% 100% 125,000 12 25,000 

 

Loading Ramps 317 22 0% 100% - - - 

 

Spill Contingency River Boat 393 8 100% 100% 40,000 8 40,000 

 

Ocean Vessel 392 2 100% 100% 250,000 10 50,000 

 

Air Boat 393 2 100% 100% 45,000 10 9,000 

 

Skimmer/Separators 338 20 100% 100% 100,000 10 200,000 

 

Booms 219 72 100% 100% 2,685 10 19,332 

 

†Activity Units

 Units Per 

Activity Units Year 

Barge Support 1 Day 120 Camp Support 1 Year 1 Drill Ship – Calm Water 1 Day 270 Drill Ship – Rough Water 1 Day 270 Equip Production Island 1 Island 1 Exploration Well 1 Well 3 Gravel Island 1 Island 1 Helicopter Support 1 Day 365 Ice Island 1 Island 1 Ice Road 10-Miles 1 Land Base Operations 1 Year 1 

 Units Per Activity Units Year Mobile Bottom Founded Structure 1 Day 270 Move Platform 1 Day 270 Offshore Pipeline 1 Mile 1 Onshore Pipeline 1 Mile 1 Personnel Transport 1 Day 365 Production Operations 1 Year 1 Production Well 1 Well 9 Seafloor Tieback Pipeline 10 Miles 1 Seismic Survey 1 Month 4 Spill Contingency 1 Year 1 Well Work-over 1 Well 30 
New Equipment Margin Matrix

Percent of Total Delivered Price

Producer Transportation to Alaska Transportation Within Alaska 

Asset Price Rail Water Truck Air Total Rail Water Truck Air 

100 Barrel Water Tank 42.0% 0.5% 1.0% 0.5% 0.0% 2.0% 3.0% 0.0% 1.0% 0.0% 300 Barrel Water Tank 40.9% 0.6% 1.3% 0.6% 0.2% 2.7% 2.0% 1.0% 2.0% 0.5% 3000 Gallon Fuel Tank 30.3% 3.0% 15.2% 2.0% 0.0% 20.2% 3.0% 5.0% 22.3% 0.0% 500 Gallon Fuel Tank 35.1% 2.0% 8.5% 2.0% 0.0% 12.5% 2.0% 3.0% 18.0% 2.0% 60 Foot Sleigh 29.7% 0.0% 0.0% 0.0% 0.0% 0.0% 0.2% 0.8% 3.0% 0.0% 966 CAT Loader 71.4% 2.2% 5.0% 2.2% 0.0% 9.4% 0.3% 0.7% 1.3% 0.0% 988 CAT Loader 80.2% 0.5% 1.1% 0.5% 0.0% 2.1% 0.1% 0.2% 0.4% 0.0% Air Boat 88.3% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 6.7% 0.0% Angle Blade 31.7% 5.0% 15.0% 5.0% 0.0% 25.0% 0.0% 0.0% 0.0% 0.0% Auger 44.1% 0.2% 0.3% 0.2% 0.0% 0.8% 0.5% 0.5% 0.5% 0.0% Backhoe 72.9% 2.0% 4.3% 1.9% 0.0% 8.2% 0.4% 0.4% 1.2% 0.0% Booms 91.8% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 2.4% 0.8% Bridge Section 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Bus 60.0% 1.5% 2.5% 1.5% 0.5% 6.0% 3.0% 1.5% 6.0% 1.5% CAT Challenger 70.9% 2.2% 4.6% 2.1% 0.0% 8.9% 0.4% 0.8% 2.0% 0.0% Cement Mixing Plant 76.8% 1.2% 2.4% 1.2% 0.0% 4.8% 0.3% 0.3% 0.8% 0.0% Compactor 77.3% 1.0% 2.2% 1.0% 0.0% 4.2% 0.3% 0.2% 1.0% 0.0% Concrete Truck 77.0% 1.2% 2.3% 1.2% 0.0% 4.7% 0.4% 0.4% 0.5% 0.0% Conveyors 77.0% 1.2% 2.5% 1.3% 0.0% 5.0% 0.3% 0.4% 0.3% 0.0% Crane 77.0% 1.2% 2.5% 1.3% 0.0% 5.0% 0.3% 0.4% 0.3% 0.0% D10 CAT 81.0% 0.3% 0.8% 0.4% 0.0% 1.5% 0.2% 0.1% 0.2% 0.0% D6 CAT 72.9% 2.0% 4.3% 1.9% 0.0% 8.2% 0.4% 0.4% 1.2% 0.0% D7 CAT 74.4% 1.7% 3.6% 1.6% 0.0% 6.9% 0.3% 0.4% 1.0% 0.0% Ditch Witch 72.9% 2.0% 4.3% 1.9% 0.0% 8.2% 0.4% 0.4% 1.2% 0.0% Dive Boat 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Drill Rig 70.8% 0.9% 2.0% 0.9% 1.5% 5.3% 1.0% 1.5% 2.5% 0.3% Drill Ship 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Drilling Machine 76.8% 1.2% 2.4% 1.2% 0.0% 4.8% 0.3% 0.3% 0.8% 0.0% Dump Truck 68.0% 2.7% 6.0% 2.7% 0.0% 11.4% 0.8% 0.8% 2.0% 0.0% Electrical Apparatus, NEC 77.2% 0.2% 0.2% 0.2% 0.2% 0.8% 0.1% 0.1% 0.3% 0.3% Engine 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Forklift 73.0% 0.5% 1.2% 0.5% 0.1% 2.3% 1.6% 1.5% 1.6% 0.0% Front-end Loader 73.0% 0.5% 1.2% 0.5% 0.1% 2.3% 1.6% 1.5% 1.6% 0.0% Fuel Barge 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Generator 72.9% 0.6% 1.5% 0.4% 0.1% 2.6% 0.2% 0.2% 1.5% 0.1% Hammer 76.8% 1.2% 2.4% 1.2% 0.0% 4.8% 0.3% 0.3% 0.8% 0.0% Heater 41.9% 0.5% 0.6% 0.5% 0.5% 2.1% 0.5% 0.5% 2.0% 1.2% Helicopter 93.6% 0.1% 0.1% 0.1% 0.1% 0.4% 0.0% 0.0% 0.1% 0.0% Hoists 77.0% 1.2% 2.5% 1.3% 0.0% 5.0% 0.3% 0.4% 0.3% 0.0% Hydraulic Pump 43.3% 0.3% 0.5% 0.3% 0.1% 1.2% 0.8% 0.8% 0.8% 0.0% Hydraulics 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Ice Breaker 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Ice Mill 75.1% 0.1% 0.3% 0.1% 0.1% 0.6% 0.3% 0.2% 0.5% 0.1% Incinerator 72.4% 1.0% 3.0% 0.8% 0.0% 4.8% 0.3% 0.3% 1.9% 0.0% Industrial Lights 79.3% 0.1% 0.1% 0.1% 0.0% 0.3% 0.0% 0.0% 0.1% 0.0% Insulated Drum 43.3% 0.3% 0.5% 0.3% 0.1% 1.2% 0.8% 0.8% 0.8% 0.0% Insulation 44.4% 0.1% 0.2% 0.2% 0.1% 0.6% 0.3% 0.1% 0.4% 0.4% Interest 100.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Large Grader 69.0% 2.7% 5.5% 2.7% 0.0% 10.9% 0.6% 0.5% 2.0% 0.0% Large Loader 67.6% 1.3% 2.6% 1.0% 0.3% 5.2% 2.2% 1.0% 6.0% 1.0% Large Water Truck 50.5% 3.5% 5.4% 1.4% 0.5% 10.8% 8.0% 3.7% 10.0% 0.0% Loading Ramps 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Long Reach Attachment 72.7% 0.5% 1.7% 0.5% 0.0% 2.7% 0.2% 0.0% 0.4% 0.0% MBFS 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 

APPENDIX TABLE A-2
New Equipment Margin Matrix

Percent of Total Delivered Price

Producer Transportation to Alaska Transportation Within Alaska 

Asset Price Rail Water Truck Air Total Rail Water Truck Air 

APPENDIX TABLE A-2

Motor Vehicle Parts 35.7% 1.5% 2.6% 1.5% 0.3% 5.9% 4.0% 3.9% 4.0% 0.0% Nodwell 75.8% 1.0% 2.3% 0.9% 0.3% 4.5% 0.6% 0.6% 1.2% 0.3% Ocean Vessel 92.6% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.6% 1.8% 0.0% Pickup Truck 60.0% 1.5% 2.5% 1.5% 0.5% 6.0% 3.0% 1.5% 6.0% 1.5% Pile Driving Template 76.8% 1.2% 2.4% 1.2% 0.0% 4.8% 0.3% 0.3% 0.8% 0.0% Pipeline Coating Machine 79.3% 0.1% 0.1% 0.1% 0.0% 0.3% 0.0% 0.0% 0.1% 0.0% Pipeline Heating Machine 79.3% 0.1% 0.1% 0.1% 0.0% 0.3% 0.0% 0.0% 0.1% 0.0% Power Facility Construction 100.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Power Generator 77.9% 0.1% 0.3% 0.1% 0.0% 0.5% 0.0% 0.1% 0.2% 0.0% Prefabricated Modules 32.6% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 3.8% 6.0% 0.0% Relays 77.2% 0.2% 0.2% 0.2% 0.2% 0.8% 0.1% 0.1% 0.3% 0.3% Rig Mats 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% River Boat 87.5% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 7.5% 0.0% Seismic Equipment 82.7% 0.0% 0.0% 0.0% 0.2% 0.2% 0.0% 0.0% 0.0% 0.1% Self Propelled Barge 76.5% 0.2% 0.4% 0.2% 0.0% 0.8% 0.1% 0.2% 0.1% 0.0% Sewage Treatment Construction 100.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Sewage Treatment Equipment 63.5% 0.4% 1.0% 0.4% 0.4% 2.2% 0.2% 0.3% 1.5% 0.2% Shaker Truck 78.8% 0.7% 2.0% 0.7% 0.0% 3.4% 0.2% 0.2% 0.4% 0.0% Skimmer/Separators 94.7% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.2% 0.1% Small Flatbed Truck 53.0% 1.0% 9.0% 0.0% 0.0% 10.0% 15.0% 0.0% 5.0% 0.0% Small Grader 76.0% 0.5% 1.2% 0.5% 0.1% 2.3% 1.6% 1.5% 1.6% 0.0% Small Rollagon 63.8% 1.6% 2.8% 1.6% 0.4% 6.4% 4.3% 4.3% 4.3% 0.0% Small Water Truck 53.0% 1.0% 9.0% 0.0% 0.0% 10.0% 15.0% 0.0% 5.0% 0.0% Snow Melter 72.4% 1.0% 3.0% 0.8% 0.0% 4.8% 0.3% 0.3% 1.9% 0.0% Snowblower 43.0% 0.0% 13.3% 0.0% 0.0% 13.3% 6.7% 0.0% 20.0% 0.0% Survey Equipment 82.5% 0.0% 0.0% 0.0% 0.3% 0.3% 0.0% 0.0% 0.0% 0.2% Switchgear 77.2% 0.2% 0.2% 0.2% 0.2% 0.8% 0.1% 0.1% 0.3% 0.3% Texoma Drill 72.9% 2.0% 4.3% 1.9% 0.0% 8.2% 0.4% 0.4% 1.2% 0.0% Tires 39.0% 1.0% 1.7% 1.0% 0.2% 3.9% 2.6% 2.6% 2.6% 0.0% Transformers 77.2% 0.2% 0.2% 0.2% 0.2% 0.8% 0.1% 0.1% 0.3% 0.3% Transport Trailer 71.4% 2.2% 5.0% 2.2% 0.0% 9.4% 0.3% 0.7% 1.3% 0.0% Truck Tractor 53.0% 1.0% 9.0% 0.0% 0.0% 10.0% 15.0% 0.0% 5.0% 0.0% Truck Trailer 71.4% 2.2% 5.0% 2.2% 0.0% 9.4% 0.3% 0.7% 1.3% 0.0% Tug 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Van 60.0% 1.5% 2.5% 1.5% 0.5% 6.0% 3.0% 1.5% 6.0% 1.5% Water Pumps 42.7% 0.4% 0.5% 0.5% 0.3% 1.7% 1.0% 0.2% 1.0% 1.0% Water Treatment Construction 100.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Water Treatment Equipment 62.8% 0.4% 0.4% 0.4% 0.4% 1.6% 0.2% 0.2% 1.0% 0.2% Welding Machine 79.3% 0.1% 0.1% 0.1% 0.0% 0.3% 0.0% 0.0% 0.1% 0.0% Wiring Devices 77.2% 0.2% 0.2% 0.2% 0.2% 0.8% 0.1% 0.1% 0.3% 0.3% Workboat 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 
Used Equipment Margin Matrix

Percent of Total Delivered Price

Producer Transportation to Alaska Transportation Within Alaska 

Asset Price Rail Water Truck Air Total Rail Water Truck Air 

100 Barrel Water Tank 38.4% 1.0% 2.2% 1.0% 0.0% 4.2% 3.5% 1.5% 3.5% 0.0% 300 Barrel Water Tank 36.4% 1.2% 2.7% 1.2% 0.4% 5.5% 3.9% 2.0% 4.0% 1.0% 3000 Gallon Fuel Tank 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 500 Gallon Fuel Tank 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 60 Foot Sleigh 39.9% 0.0% 0.0% 0.0% 0.0% 0.0% 2.0% 2.0% 5.0% 1.0% 966 CAT Loader 36.2% 0.2% 0.2% 0.2% 0.2% 0.8% 1.1% 1.1% 4.5% 1.0% 988 CAT Loader 40.5% 0.1% 0.1% 0.2% 0.2% 0.6% 0.0% 0.0% 2.0% 1.5% Air Boat 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Angle Blade 38.4% 0.4% 1.5% 0.4% 0.2% 2.5% 2.0% 2.0% 5.1% 1.0% Auger 44.1% 0.1% 0.2% 0.1% 0.0% 0.4% 0.5% 0.5% 0.5% 0.0% Backhoe 31.9% 0.2% 0.1% 0.2% 0.2% 0.7% 0.5% 0.5% 4.0% 1.3% Booms 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Bridge Section 20.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 1.0% 0.0% Bus 27.7% 0.5% 0.5% 0.5% 0.5% 2.0% 2.0% 2.0% 16.7% 3.0% CAT Challenger 30.3% 0.2% 0.2% 0.2% 0.2% 0.8% 2.0% 2.0% 5.1% 1.0% Cement Mixing Plant 40.5% 0.1% 0.1% 0.2% 0.2% 0.6% 0.0% 0.0% 2.0% 1.5% Compactor 40.5% 0.1% 0.1% 0.2% 0.2% 0.6% 0.0% 0.0% 2.0% 1.5% Concrete Truck 24.5% 0.0% 0.0% 0.5% 0.5% 1.0% 0.0% 0.0% 2.0% 1.1% Conveyors 24.5% 0.0% 0.0% 0.5% 0.5% 1.0% 0.0% 0.0% 2.0% 1.1% Crane 24.5% 0.0% 0.0% 0.5% 0.5% 1.0% 0.0% 0.0% 2.0% 1.1% D10 CAT 40.5% 0.1% 0.1% 0.2% 0.2% 0.6% 0.0% 0.0% 2.0% 1.5% D6 CAT 31.9% 0.2% 0.1% 0.2% 0.2% 0.7% 0.5% 0.5% 4.0% 1.3% D7 CAT 27.5% 0.1% 0.1% 0.1% 0.2% 0.5% 0.7% 0.8% 3.0% 0.4% Ditch Witch 31.9% 0.2% 0.1% 0.2% 0.2% 0.7% 0.5% 0.5% 4.0% 1.3% Dive Boat 94.0% 0.0% 6.0% 0.0% 0.0% 6.0% 0.0% 0.0% 0.0% 0.0% Drill Rig 28.9% 0.1% 0.1% 0.1% 0.1% 0.4% 0.0% 0.1% 0.1% 0.1% Drill Ship 94.0% 0.0% 6.0% 0.0% 0.0% 6.0% 0.0% 0.0% 0.0% 0.0% Drilling Machine 40.5% 0.1% 0.1% 0.2% 0.2% 0.6% 0.0% 0.0% 2.0% 1.5% Dump Truck 24.5% 0.0% 0.0% 0.5% 0.5% 1.0% 0.0% 0.0% 2.0% 1.1% Electrical Apparatus, NEC 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Engine 43.6% 0.2% 0.6% 0.2% 0.1% 1.1% 0.6% 0.4% 1.0% 0.2% Forklift 36.4% 0.5% 0.5% 0.5% 0.5% 2.0% 3.0% 3.0% 3.0% 1.5% Front-end Loader 36.4% 0.5% 0.5% 0.5% 0.5% 2.0% 3.0% 3.0% 3.0% 1.5% Fuel Barge 94.0% 0.0% 6.0% 0.0% 0.0% 6.0% 0.0% 0.0% 0.0% 0.0% Generator 41.5% 0.2% 0.3% 0.3% 0.2% 1.0% 1.0% 1.0% 3.0% 1.0% Hammer 40.5% 0.1% 0.1% 0.2% 0.2% 0.6% 0.0% 0.0% 2.0% 1.5% Heater 41.9% 0.5% 0.6% 0.5% 0.5% 2.1% 0.5% 0.5% 2.0% 1.2% Helicopter 45.0% 0.5% 0.5% 0.5% 0.5% 2.0% 0.0% 0.0% 0.1% 0.0% Hoists 24.5% 0.0% 0.0% 0.5% 0.5% 1.0% 0.0% 0.0% 2.0% 1.1% Hydraulic Pump 43.5% 0.2% 0.3% 0.2% 0.1% 0.6% 0.8% 0.8% 0.9% 0.0% Hydraulics 44.7% 0.1% 0.1% 0.1% 0.1% 0.4% 0.2% 0.1% 0.3% 0.2% Ice Breaker 94.0% 0.0% 6.0% 0.0% 0.0% 6.0% 0.0% 0.0% 0.0% 0.0% Ice Mill 43.0% 0.0% 0.0% 0.0% 0.0% 0.0% 1.2% 0.8% 2.0% 0.3% Incinerator 40.1% 0.1% 0.2% 0.1% 0.1% 0.5% 1.0% 2.0% 5.0% 1.0% Industrial Lights 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Insulated Drum 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Insulation 44.4% 0.1% 0.2% 0.2% 0.1% 0.6% 0.3% 0.1% 0.4% 0.4% Interest 100.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Large Grader 30.9% 0.0% 0.0% 0.0% 0.0% 0.0% 4.9% 2.2% 13.0% 2.0% Large Loader 30.9% 0.0% 0.0% 0.0% 0.0% 0.0% 4.9% 2.2% 13.0% 2.0% Large Water Truck 22.7% 0.0% 0.0% 0.0% 0.0% 0.0% 14.2% 6.5% 17.6% 0.0% Loading Ramps 20.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 1.0% 0.0% Long Reach Attachment 44.8% 0.1% 0.1% 0.1% 0.2% 0.5% 0.0% 0.0% 0.2% 0.2% MBFS 94.0% 0.0% 6.0% 0.0% 0.0% 6.0% 0.0% 0.0% 0.0% 0.0% 

APPENDIX TABLE A-3
Used Equipment Margin Matrix

Percent of Total Delivered Price

Producer Transportation to Alaska Transportation Within Alaska 

Asset Price Rail Water Truck Air Total Rail Water Truck Air 

APPENDIX TABLE A-3

Motor Vehicle Parts 37.0% 0.5% 0.5% 1.1% 1.0% 3.1% 3.5% 1.8% 4.0% 3.0% Nodwell 39.4% 0.2% 0.3% 0.3% 0.2% 1.0% 1.5% 1.5% 6.0% 0.9% Ocean Vessel 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Pickup Truck 27.7% 0.5% 0.5% 0.5% 0.5% 2.0% 2.0% 2.0% 16.7% 3.0% Pile Driving Template 40.5% 0.1% 0.1% 0.2% 0.2% 0.6% 0.0% 0.0% 2.0% 1.5% Pipeline Coating Machine 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Pipeline Heating Machine 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Power Facility Construction 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Power Generator 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Prefabricated Modules 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Relays 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Rig Mats 20.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 1.0% 0.0% River Boat 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Seismic Equipment 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Self Propelled Barge 33.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.4% 0.4% 0.0% Sewage Treatment Construction 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Sewage Treatment Equipment 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Shaker Truck 42.3% 0.5% 0.5% 0.5% 0.5% 2.0% 0.7% 0.7% 2.0% 0.2% Skimmer/Separators 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Small Flatbed Truck 20.0% 0.0% 0.0% 2.0% 0.0% 2.0% 15.0% 6.5% 20.0% 0.0% Small Grader 36.4% 0.5% 0.5% 0.5% 0.5% 2.0% 3.0% 3.0% 3.0% 1.5% Small Rollagon 33.0% 0.5% 0.5% 0.5% 0.5% 2.0% 4.0% 4.0% 4.0% 2.0% Small Water Truck 20.0% 0.0% 0.0% 2.0% 0.0% 2.0% 15.0% 6.5% 20.0% 0.0% Snow Melter 40.1% 0.1% 0.2% 0.1% 0.1% 0.5% 1.0% 2.0% 5.0% 1.0% Snowblower 26.6% 0.0% 0.0% 0.0% 0.0% 0.0% 10.0% 5.0% 25.0% 0.0% Survey Equipment 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Switchgear 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Texoma Drill 24.5% 0.0% 0.0% 0.5% 0.5% 1.0% 0.0% 0.0% 2.0% 1.1% Tires 39.0% 1.0% 1.0% 1.0% 0.8% 3.8% 2.3% 1.0% 4.0% 0.5% Transformers 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Transport Trailer 36.2% 0.2% 0.2% 0.2% 0.2% 0.8% 1.1% 1.1% 4.5% 1.0% Truck Tractor 20.0% 0.0% 0.0% 2.0% 0.0% 2.0% 15.0% 6.5% 20.0% 0.0% Truck Trailer 36.2% 0.2% 0.2% 0.2% 0.2% 0.8% 1.1% 1.1% 4.5% 1.0% Tug 94.0% 0.0% 6.0% 0.0% 0.0% 6.0% 0.0% 0.0% 0.0% 0.0% Van 27.7% 0.5% 0.5% 0.5% 0.5% 2.0% 2.0% 2.0% 16.7% 3.0% Water Pumps 40.4% 0.7% 0.9% 0.9% 0.5% 3.0% 1.9% 0.4% 1.9% 1.9% Water Treatment Construction 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Water Treatment Equipment 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Welding Machine 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Wiring Devices 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Workboat 94.0% 0.0% 6.0% 0.0% 0.0% 6.0% 0.0% 0.0% 0.0% 0.0% 
RPC Coefficients for Capital Expenditures and Associated Margins

Commodity NSB Other AK Other US Foreign

100 Barrel Water Tank 0.0% 5.0% 70.0% 25.0%

300 Barrel Water Tank 0.0% 5.0% 70.0% 25.0%

3000 Gallon Fuel Tank 0.0% 5.0% 70.0% 25.0%

500 Gallon Fuel Tank 0.0% 5.0% 70.0% 25.0%

60 Foot Sleigh 0.0% 95.0% 0.0% 5.0%

966 CAT Loader 0.0% 5.0% 70.0% 25.0%

988 CAT Loader 0.0% 5.0% 70.0% 25.0%

Air Boat 0.0% 100.0% 0.0% 0.0%

Angle Blade 0.0% 5.0% 70.0% 25.0%

Auger 0.0% 5.0% 70.0% 25.0%

Backhoe 0.0% 5.0% 70.0% 25.0%

Booms 0.0% 100.0% 0.0% 0.0%

Bridge Section 100.0% 0.0% 0.0% 0.0%

Bus 0.0% 5.0% 70.0% 25.0%

CAT Challenger 0.0% 5.0% 70.0% 25.0%

Cement Mixing Plant 0.0% 5.0% 85.0% 10.0%

Compactor 0.0% 5.0% 70.0% 25.0%

Concrete Truck 0.0% 5.0% 70.0% 25.0%

Conveyors 0.0% 5.0% 70.0% 25.0%

Crane 0.0% 5.0% 70.0% 25.0%

D10 CAT 0.0% 5.0% 70.0% 25.0%

D6 CAT 0.0% 5.0% 70.0% 25.0%

D7 CAT 0.0% 5.0% 70.0% 25.0%

Ditch Witch 0.0% 5.0% 70.0% 25.0%

Dive Boat 0.0% 75.0% 20.0% 5.0%

Drill Rig 0.0% 5.0% 70.0% 25.0%

Drill Ship 0.0% 75.0% 20.0% 5.0%

Drilling Machine 0.0% 5.0% 70.0% 25.0%

Dump Truck 0.0% 5.0% 70.0% 25.0%

Electrical Apparatus, NEC 0.0% 5.0% 70.0% 25.0%

Engine 0.0% 0.0% 100.0% 0.0%

Forklift 0.0% 5.0% 70.0% 25.0%

Front-end Loader 0.0% 5.0% 70.0% 25.0%

Fuel Barge 0.0% 75.0% 20.0% 5.0%

Generator 0.0% 5.0% 70.0% 25.0%

Hammer 0.0% 5.0% 70.0% 25.0%

Heater 0.0% 5.0% 70.0% 25.0%

Helicopter 0.0% 5.0% 85.0% 10.0%

Hoists 0.0% 5.0% 70.0% 25.0%

Hydraulic Pump 0.0% 5.0% 70.0% 25.0%

Hydraulics 0.0% 5.0% 70.0% 25.0%

Ice Breaker 0.0% 10.0% 45.0% 45.0%

APPENDIX TABLE A-4
RPC Coefficients for Capital Expenditures and Associated Margins

Commodity NSB Other AK Other US Foreign

APPENDIX TABLE A-4

Ice Mill 0.0% 5.0% 70.0% 25.0%

Incinerator 0.0% 5.0% 70.0% 25.0%

Industrial Lights 0.0% 5.0% 70.0% 25.0%

Insulated Drum 0.0% 5.0% 70.0% 25.0%

Insulation 0.0% 5.0% 70.0% 25.0%

Interest 5.0% 45.0% 50.0% 0.0%

Large Grader 0.0% 5.0% 70.0% 25.0%

Large Loader 0.0% 5.0% 70.0% 25.0%

Large Water Truck 0.0% 5.0% 70.0% 25.0%

Loading Ramps 50.0% 50.0% 0.0% 0.0%

Long Reach Attachment 0.0% 5.0% 70.0% 25.0%

MBFS 0.0% 75.0% 20.0% 5.0%

Motor Vehicle Parts 0.0% 5.0% 70.0% 25.0%

Nodwell 0.0% 5.0% 0.0% 100.0%

Ocean Vessel 0.0% 100.0% 0.0% 0.0%

Pickup Truck 0.0% 5.0% 70.0% 25.0%

Pile Driving Template 0.0% 5.0% 70.0% 25.0%

Pipeline Coating Machine 0.0% 5.0% 70.0% 25.0%

Pipeline Heating Machine 0.0% 5.0% 70.0% 25.0%

Power Facility Construction 75.0% 24.0% 0.0% 1.0%

Power Generator 0.0% 5.0% 70.0% 25.0%

Prefabricated Modules 0.0% 50.0% 25.0% 25.0%

Relays 0.0% 5.0% 70.0% 25.0%

Rig Mats 50.0% 50.0% 0.0% 0.0%

River Boat 0.0% 100.0% 0.0% 0.0%

Seismic Equipment 0.0% 5.0% 70.0% 25.0%

Self Propelled Barge 0.0% 5.0% 70.0% 25.0%

Sewage Treatment Construction 75.0% 24.0% 0.0% 1.0%

Sewage Treatment Equipment 0.0% 5.0% 70.0% 25.0%

Shaker Truck 0.0% 5.0% 70.0% 25.0%

Skimmer/Separators 0.0% 100.0% 0.0% 0.0%

Small Flatbed Truck 0.0% 5.0% 70.0% 25.0%

Small Grader 0.0% 5.0% 70.0% 25.0%

Small Rollagon 0.0% 5.0% 70.0% 25.0%

Small Water Truck 0.0% 5.0% 70.0% 25.0%

Snow Melter 0.0% 5.0% 70.0% 25.0%

Snowblower 0.0% 5.0% 70.0% 25.0%

Survey Equipment 0.0% 5.0% 70.0% 25.0%

Switchgear 0.0% 5.0% 70.0% 25.0%

Texoma Drill 0.0% 5.0% 70.0% 25.0%

Tires 0.0% 5.0% 70.0% 25.0%

Transformers 0.0% 5.0% 70.0% 25.0%
RPC Coefficients for Capital Expenditures and Associated Margins

Commodity NSB Other AK Other US Foreign

APPENDIX TABLE A-4

Transport Trailer 0.0% 5.0% 70.0% 25.0%

Truck Tractor 0.0% 5.0% 70.0% 25.0%

Truck Trailer 0.0% 5.0% 70.0% 25.0%

Tug 0.0% 75.0% 20.0% 5.0%

Van 0.0% 5.0% 70.0% 25.0%

Water Pumps 0.0% 5.0% 70.0% 25.0%

Water Treatment Construction 75.0% 24.0% 0.0% 1.0%

Water Treatment Equipment 0.0% 5.0% 70.0% 25.0%

Welding Machine 0.0% 5.0% 70.0% 25.0%

Wiring Devices 0.0% 5.0% 70.0% 25.0%

Workboat 0.0% 75.0% 20.0% 5.0%

Rail to Alaska 0.0% 50.0% 50.0% 0.0%

Rail Within Alaska 0.0% 100.0% 0.0% 0.0%

Water to Alaska 0.0% 50.0% 50.0% 0.0%

Water Within Alaska 0.0% 100.0% 0.0% 0.0%

Truck to Alaska 20.0% 30.0% 50.0% 0.0%

Truck Within Alaska 25.0% 75.0% 0.0% 0.0%

Air to Alaska 20.0% 30.0% 50.0% 0.0%

Air Within Alaska 25.0% 75.0% 0.0% 0.0%

Wholesale Trade 10.0% 60.0% 30.0% 0.0%

Labor for Retrofitting 30.0% 60.0% 10.0% 0.0%
APPENDIX TALBE A-5

Asset to IMPLAN Sector Concordance

IMPLAN

Asset/Commodity Sector Sector Description

100 Barrel Water Tank 284 Fabricated Plate Work

300 Barrel Water Tank 284 Fabricated Plate Work

3000 Gallon Fuel Tank 284 Fabricated Plate Work

500 Gallon Fuel Tank 284 Fabricated Plate Work

60 Foot Sleigh 399 Transportation Equipment, N.E.C.

966 CAT Loader 311 Construction Machinery and Equipment

988 CAT Loader 311 Construction Machinery and Equipment

Air Boat 393 Boat Building and Repairing

Angle Blade 311 Construction Machinery and Equipment

Auger 312 Mining Machinery, Except Oil Field

Backhoe 311 Construction Machinery and Equipment

Booms 219 Fabricated Rubber Products, N.E.C.

Bridge Section 282 Fabricated Structural Metal

Bus 384 Motor Vehicles

CAT Challenger 311 Construction Machinery and Equipment

Cement Mixing Plant 311 Construction Machinery and Equipment

Compactor 311 Construction Machinery and Equipment

Concrete Truck 317 Industrial Trucks and Tractors

Conveyors 315 Conveyors and Conveying Equipment

Crane 311 Construction Machinery and Equipment

D10 CAT 311 Construction Machinery and Equipment

D6 CAT 311 Construction Machinery and Equipment

D7 CAT 311 Construction Machinery and Equipment

Ditch Witch 311 Construction Machinery and Equipment

Dive Boat 393 Boat Building and Repairing

Drill Rig 313 Oil Field Machinery

Drill Ship 392 Ship Building and Repairing

Drilling Machine 312 Mining Machinery, Except Oil Field

Dump Truck 317 Industrial Trucks and Tractors

Electrical Apparatus, NEC 360 Electrical Apparatus, NEC

Engine 308 Internal Combustion Engines

Forklift 317 Industrial Trucks and Tractors

Front-end Loader 311 Construction Machinery and Equipment

Fuel Barge 393 Boat Building and Repairing

Generator 357 Motors and Generators

Hammer 311 Construction Machinery and Equipment

Heater 386 Motor Vehicle Parts and Accessories

Hellicopter 389 Aircraft

Hoists 316 Hoists, Cranes, and Monorails

Hydraulic Pump 352 Fluid Power Pumps and Motors

Hydraulics 352 Fluid Power Pumps and Motors

Ice Breaker 392 Ship Building and Repairing

Ice Mill 311 Construction Machinery and Equipment

Incinerator 337 Industrial Furnaces and Ovens

Industrial Lights 369 Lighting Fixtures and Equipment

Insulated Drum 317 Industrial Trucks and Tractors

Insulation 251 Mineral Wool

Large Grader 311 Construction Machinery and Equipment

Large Loader 311 Construction Machinery and Equipment

Large Water Truck 317 Industrial Trucks and Tractors

Loading Ramps 317 Industrial Trucks and Tractors

Long Reach Attachment 311 Construction Machinery and Equipment

Mobile Bottom Founded Structure (MBFS) 392 Ship Building and Repairing

Motor Vehicle Parts 386 Motor Vehicle Parts and Accessories
APPENDIX TALBE A-5

Asset to IMPLAN Sector Concordance

IMPLAN

Asset/Commodity Sector Sector Description

Nodwell 311 Construction Machinery and Equipment

Ocean Vessel 392 Ship Building and Repairing

Pickup Truck 384 Motor Vehicles

Pile Driving Template 311 Construction Machinery and Equipment

Pipeline Coating Machine 331 Special Industry Machinery, N.E.C.

Pipeline Heating Machine 331 Special Industry Machinery, N.E.C.

Power Facility Construction 050 New Utility Structures

Power Generator 357 Motors and Generators

Prefabricated Modules 287 Fabricated Metal Buildings

Relays 359 Relays

Rig Mats 282 Fabricated Structural Metal

River Boat 393 Boat Building and Repairing

Seismic Equipment 403 Mechanical Measuring Devices

Self Propelled Barge 392 Ship Building and Repairing

Sewage Treatment Construction 50 New Utility Structures

Sewage Treatment Equipment 349 Service Industry Machines, N.E.C.

Shaker Truck 312 Mining Machinery, Except Oil Field

Skimmer/Separators 338 General Industrial Machinery, N.E.C.

Small Flatbed Truck 384 Motor Vehicles

Small Grader 311 Construction Machinery and Equipment

Small Rollagon 311 Construction Machinery and Equipment

Small Water Truck 317 Industrial Trucks and Tractors

Snow Melter 281 Heating Equipment, Except Electrical

Snowblower 311 Construction Machinery and Equipment

Survey Equipment 400 Search and Navigation Equipment

Switchgear 356 Switchgear

Texoma Drill 312 Mining Machinery, Except Oil Field

Tires 215 Tires and Inner Tubes

Transformers 355 Transformers

Transport Trailer 317 Industrial Trucks and Tractors

Truck Tractor 384 Motor Vehicles

Truck Trailer 387 Truck Trailers

Tug 392 Ship Building and Repairing

Van 384 Motor Vehicles

Water Pumps 332 Pumps and Compressors

Water Treatment Construction 050 New Utility Structures

Water Treatment Equipment 349 Service Industry Machines, N.E.C.

Welding Machine 324 Welding Apparatus

Wiring Devices 368 Wiring Devices

Workboat 392 Ship Building and Repairing

Rail to Alaska 433 Railroads and Related Services

Rail Within Alaska 433 Railroads and Related Services

Water to Alaska 436 Water Transportation

Water Within Alaska 436 Water Transportation

Truck to Alaska 435 Motor Freight Transport and Warehousing

Truck Within Alaska 435 Motor Freight Transport and Warehousing

Air to Alaska 437 Air Transportation

Air Within Alaska 437 Air Transportation

Wholesale Trade 447 Wholesale Trade

Labor for Retrofitting 482 Miscellaneous Repair Shops
APPENDIX TABLE A-6

Capital Expenditures Per Activity Unit† by Activity, Region and IMPLAN Sector

IMPLAN

Activity Sector Description NSB Other AK Other US 

Seismic Survey 251 Mineral Wool 0 34 472 

 281 Heating Equipment, Except Electrical 0 153 2,149  284 Fabricated Plate Work 0 52 734  287 Fabricated Metal Buildings 0 4,890 2,445  311 Construction Machinery and Equipment 0 5,187 25,060  312 Mining Machinery, Except Oil Field 0 8,747 122,455  337 Industrial Furnaces and Ovens 0 153 2,149  357 Motors and Generators 0 1,053 14,746  386 Motor Vehicle Parts and Accessories 0 59 825  399 Transportation Equipment, N.E.C. 0 3,861 0  400 Search and Navigation Equipment 0 619 8,663  403 Mechanical Measuring Devices 0 12,405 173,670  433 Railroads and Related Services 0 3,721 1,768  435 Motor Freight Transportation and Warehousing 2,743 7,223 1,677  436 Water Transportation 0 7,868 4,583  437 Air Transportation 468 1,100 504  447 Wholesale Trade 12,591 75,545 37,772  482 Miscellaneous Repair Shops 14,118 28,235 4,706 

TOTAL 29,919 160,905 404,378 

North Slope 050 New Utility Structures 391,686 125,340 0 Camp Support 349 Service Industry Machines, N.E.C. 0 1,267 17,744 

 355 Transformers 0 1,861 26,051  356 Switchgear 0 1,861 26,051  357 Motors and Generators 0 9,388 131,438  359 Relays 0 1,861 26,051  360 Electrical Apparatus, NEC 0 1,861 26,051  368 Wiring Devices 0 1,861 26,051  433 Railroads and Related Services 0 763 442  435 Motor Freight Transportation and Warehousing 600 1,535 442  436 Water Transportation 0 1,314 735  437 Air Transportation 329 795 321  447 Wholesale Trade 8,311 49,864 24,932  456 Banking 30,813 277,314 308,127  482 Miscellaneous Repair Shops 9,800 19,600 3,267 

TOTAL 441,539 496,485 617,704 
APPENDIX TABLE A-6

Capital Expenditures Per Activity Unit† by Activity, Region and IMPLAN Sector

IMPLAN

Activity Sector Description NSB Other AK Other US 

General Personnel 384 Motor Vehicles 0 2 23 Transport 433 Railroads and Related Services 020

 435 Motor Freight Transportation and Warehousing 3 10 0  436 Water Transportation 020 437 Air Transportation 120 447 Wholesale Trade 1 7 3  482 Miscellaneous Repair Shops 8 15 3 

TOTAL 13 40 30 

Construct Ice Road 215 Tires and Inner Tubes 0 1 14 

 251 Mineral Wool 0 76 1,060  284 Fabricated Plate Work 0 231 3,240  287 Fabricated Metal Buildings 0 147 73  308 Internal Combustion Engines 0 0 91  311 Construction Machinery and Equipment 0 857 12,003  312 Mining Machinery, Except Oil Field 0 232 3,253  317 Industrial Trucks and Tractors 0 622 8,706  332 Pumps and Compressors 0 253 3,545  352 Fluid Power Pumps and Motors 0 201 2,808  357 Motors and Generators 0 36 499  384 Motor Vehicles 0 135 1,897  386 Motor Vehicle Parts and Accessories 0 99 1,389  399 Transportation Equipment, N.E.C. 0 191 0  433 Railroads and Related Services 0 4,861 539  435 Motor Freight Transportation and Warehousing 1,575 4,427 496  436 Water Transportation 0 3,173 1,435  437 Air Transportation 184 488 109  447 Wholesale Trade 1,563 9,380 4,690  482 Miscellaneous Repair Shops 8,877 17,754 2,959 

TOTAL 12,200 43,164 48,806 
APPENDIX TABLE A-6

Capital Expenditures Per Activity Unit† by Activity, Region and IMPLAN Sector

IMPLAN

Activity Sector Description NSB Other AK Other US 

Construct Ice Island 215 Tires and Inner Tubes 002

 251 Mineral Wool 0 50 702  284 Fabricated Plate Work 0 271 3,794  287 Fabricated Metal Buildings 0 147 73  308 Internal Combustion Engines 0 0 118  311 Construction Machinery and Equipment 0 366 5,124  312 Mining Machinery, Except Oil Field 0 22 310  317 Industrial Trucks and Tractors 0 750 10,501  332 Pumps and Compressors 0 297 4,152  352 Fluid Power Pumps and Motors 0 27 383  357 Motors and Generators 0 36 499  384 Motor Vehicles 0 54 759  386 Motor Vehicle Parts and Accessories 0 39 552  399 Transportation Equipment, N.E.C. 0 191 0  433 Railroads and Related Services 0 4,251 429  435 Motor Freight Transportation and Warehousing 1,158 3,247 378  436 Water Transportation 0 2,288 1,134  437 Air Transportation 131 347 75  447 Wholesale Trade 1,118 6,706 3,353  482 Miscellaneous Repair Shops 6,062 12,124 2,021 

TOTAL 8,468 31,212 34,358 

Move Drill Ships and 392 Ship Building and Repairing 0 38,723 22,264 Mobile Bottom Founded 393 Boat Building and Repairing 0 5,222 1,393 Structures 433 Railroads and Related Services 000

 435 Motor Freight Transportation and Warehousing 000 436 Water Transportation 0 2,650 2,650  437 Air Transportation 000 447 Wholesale Trade 000 482 Miscellaneous Repair Shops 000

TOTAL 0 46,595 26,307 
APPENDIX TABLE A-6

Capital Expenditures Per Activity Unit† by Activity, Region and IMPLAN Sector

IMPLAN

Activity Sector Description NSB Other AK Other US 

Operate Exploration Drill 392 Ship Building and Repairing 0 21,933 5,849 Drill Ship in Calm Waters 393 Boat Building and Repairing 0 5,222 1,393 

 433 Railroads and Related Services 000 435 Motor Freight Transportation and Warehousing 000 436 Water Transportation 0 1,156 1,156  437 Air Transportation 000 447 Wholesale Trade 000 482 Miscellaneous Repair Shops 000

TOTAL 0 28,311 8,397 

Operate Exploration Drill 392 Ship Building and Repairing 0 60,656 28,113 Drill Ship in Rough Waters 393 Boat Building and Repairing 0 5,222 1,393 

 433 Railroads and Related Services 000

 435 Motor Freight Transportation and Warehousing 000 436 Water Transportation 0 3,583 3,583  437 Air Transportation 000 447 Wholesale Trade 000 482 Miscellaneous Repair Shops 000

TOTAL 0 69,462 33,089 

Operate Mobile Bottom 392 Ship Building and Repairing 0 46,217 12,324 Founded Structure for 393 Boat Building and Repairing 0 7,833 2,089 Exploration 433 Railroads and Related Services 000

 435 Motor Freight Transportation and Warehousing 000 436 Water Transportation 0 2,300 2,300  437 Air Transportation 000 447 Wholesale Trade 000 482 Miscellaneous Repair Shops 000

TOTAL 0 56,350 16,713 

Helicopter Support 389 Aircraft 0 20 342 

 433 Railroads and Related Services 011

 435 Motor Freight Transportation and Warehousing 111 436 Water Transportation 011 437 Air Transportation 111 447 Wholesale Trade 5 32 16  456 Banking 13 117 131  482 Miscellaneous Repair Shops 65 130 22 

TOTAL 85 304 515 
APPENDIX TABLE A-6

Capital Expenditures Per Activity Unit† by Activity, Region and IMPLAN Sector

IMPLAN

Activity Sector Description NSB Other AK Other US 

Barge Support 251 Mineral Wool 000

 311 Construction Machinery and Equipment 0 5 69  386 Motor Vehicle Parts and Accessories 001 392 Ship Building and Repairing 0 85 1,191  433 Railroads and Related Services 063 435 Motor Freight Transportation and Warehousing 3 8 3  436 Water Transportation 0 14 7  437 Air Transportation 000 447 Wholesale Trade 38 227 113  482 Miscellaneous Repair Shops 138 276 46 

TOTAL 179 621 1,434 

Drill Exploration Well 311 Construction Machinery and Equipment 0 181 2,536 

 313 Oil Field Machinery 0 7,931 111,036  317 Industrial Trucks and Tractors 0 104 1,454  384 Motor Vehicles 0 29 413  433 Railroads and Related Services 0 2,271 740  435 Motor Freight Transportation and Warehousing 1,249 3,304 740  436 Water Transportation 0 3,901 1,502  437 Air Transportation 616 1,176 1,122  447 Wholesale Trade 938 5,629 2,815  456 Banking 8,024 72,219 80,244  482 Miscellaneous Repair Shops 52,349 104,698 17,450 

TOTAL 63,177 201,445 220,052 

Drill Production Well 311 Construction Machinery and Equipment 0 60 845 

 313 Oil Field Machinery 0 2,644 37,012  317 Industrial Trucks and Tractors 0 35 485  384 Motor Vehicles 0 10 138  433 Railroads and Related Services 0 757 247  435 Motor Freight Transportation and Warehousing 416 1,101 247  436 Water Transportation 0 1,300 501  437 Air Transportation 205 392 374  447 Wholesale Trade 313 1,876 938  456 Banking 2,675 24,073 26,748  482 Miscellaneous Repair Shops 17,450 34,899 5,817 

TOTAL 21,059 67,148 73,351 
APPENDIX TABLE A-6

Capital Expenditures Per Activity Unit† by Activity, Region and IMPLAN Sector

IMPLAN

Activity Sector Description NSB Other AK Other US 

Well Workover 313 Oil Field Machinery 0 288 4,037 

 433 Railroads and Related Services 0 87 29  435 Motor Freight Transportation and Warehousing 50 131 29  436 Water Transportation 0 154 61  437 Air Transportation 24 45 47  447 Wholesale Trade 22 134 67  456 Banking 195 1,753 1,948  482 Miscellaneous Repair Shops 1,456 2,911 485 

TOTAL 1,747 5,504 6,703 

Construct Gravel Island 251 Mineral Wool 0 86 1,207 (Place Gravel) 311 Construction Machinery and Equipment 0 3,404 47,656 

 317 Industrial Trucks and Tractors 0 2,524 35,342  386 Motor Vehicle Parts and Accessories 0 164 2,290  433 Railroads and Related Services 0 2,304 1,311  435 Motor Freight Transportation and Warehousing 1,503 3,670 1,397  436 Water Transportation 0 3,779 2,857  437 Air Transportation 263 716 121  447 Wholesale Trade 2,919 17,513 8,757  482 Miscellaneous Repair Shops 11,609 23,218 3,870 

TOTAL 16,293 57,378 104,809 
APPENDIX TABLE A-6

Capital Expenditures Per Activity Unit† by Activity, Region and IMPLAN Sector

IMPLAN

Activity Sector Description NSB Other AK Other US 

Construct Gravel Island 251 Mineral Wool 0 43 599 (Protect Island) 284 Fabricated Plate Work 0 56 785 

 311 Construction Machinery and Equipment 0 5,594 83,294  312 Mining Machinery, Except Oil Field 0 1,018 14,257  317 Industrial Trucks and Tractors 0 264 3,690  324 Welding Apparatus 0 57 796  332 Pumps and Compressors 0 63 886  357 Motors and Generators 0 63 878  384 Motor Vehicles 0 231 3,235  386 Motor Vehicle Parts and Accessories 0 81 1,136  433 Railroads and Related Services 0 3,000 1,181  435 Motor Freight Transportation and Warehousing 1,627 4,126 1,260  436 Water Transportation 0 3,549 2,526  437 Air Transportation 350 966 139  447 Wholesale Trade 3,445 20,668 10,334  482 Miscellaneous Repair Shops 12,948 25,896 4,316 

TOTAL 18,370 65,675 129,312 

Install Production Module 251 Mineral Wool 0 20 279 

 282 Fabricated Structural Metal 1,150 1,150 0  311 Construction Machinery and Equipment 0 4,504 63,054  317 Industrial Trucks and Tractors 0 1,417 19,833  324 Welding Apparatus 0 227 3,183  384 Motor Vehicles 0 70 978  386 Motor Vehicle Parts and Accessories 0 38 528  433 Railroads and Related Services 0 1,782 1,097  435 Motor Freight Transportation and Warehousing 1,156 2,724 1,242  436 Water Transportation 0 3,286 2,357  437 Air Transportation 208 549 125  447 Wholesale Trade 2,977 17,865 8,932  482 Miscellaneous Repair Shops 12,262 24,523 4,087 

TOTAL 17,754 58,154 105,695 
APPENDIX TABLE A-6

Capital Expenditures Per Activity Unit† by Activity, Region and IMPLAN Sector

IMPLAN

Activity Sector Description NSB Other AK Other US 

Operate Production Island 251 Mineral Wool 0 25 350 

 311 Construction Machinery and Equipment 0 2,359 33,025  384 Motor Vehicles 0 361 5,049  386 Motor Vehicle Parts and Accessories 0 47 663  433 Railroads and Related Services 0 1,255 557  435 Motor Freight Transportation and Warehousing 914 2,381 602  436 Water Transportation 0 1,838 1,154  437 Air Transportation 180 489 86  447 Wholesale Trade 1,335 8,008 4,004  482 Miscellaneous Repair Shops 5,186 10,373 1,729 

TOTAL 7,615 27,136 47,219 

Construct Trenched 251 Mineral Wool 0 52 734 Offshore Pipeline 282 Fabricated Structural Metal 1,050 0 0 

 284 Fabricated Plate Work 0 15 212  287 Fabricated Metal Buildings 0 880 440  311 Construction Machinery and Equipment 0 3,858 54,018  317 Industrial Trucks and Tractors 0 207 2,899  324 Welding Apparatus 0 971 13,600  331 Special Industry Machinery, N.E.C. 0 324 4,533  357 Motors and Generators 0 130 1,821  369 Lighting Fixtures and Equipment 0 46 648  384 Motor Vehicles 0 42 590  386 Motor Vehicle Parts and Accessories 0 99 1,393  399 Transportation Equipment, N.E.C. 0 572 0  433 Railroads and Related Services 0 1,734 991  435 Motor Freight Transportation and Warehousing 1,276 3,257 954  436 Water Transportation 0 3,176 2,118  437 Air Transportation 145 397 65  447 Wholesale Trade 2,733 16,398 8,199  482 Miscellaneous Repair Shops 10,756 21,513 3,585 

TOTAL 15,961 53,674 96,802 
APPENDIX TABLE A-6

Capital Expenditures Per Activity Unit† by Activity, Region and IMPLAN Sector

IMPLAN

Activity Sector Description NSB Other AK Other US 

Construct Onshore 251 Mineral Wool 0 26 367 Pipeline 284 Fabricated Plate Work 0 15 212 

 287 Fabricated Metal Buildings 0 880 440  311 Construction Machinery and Equipment 0 2,007 28,097  312 Mining Machinery, Except Oil Field 0 312 4,362  317 Industrial Trucks and Tractors 0 122 1,703  324 Welding Apparatus 0 486 6,800  331 Special Industry Machinery, N.E.C. 0 162 2,267  357 Motors and Generators 0 130 1,821  369 Lighting Fixtures and Equipment 0 23 324  384 Motor Vehicles 0 36 506  386 Motor Vehicle Parts and Accessories 0 50 696  399 Transportation Equipment, N.E.C. 0 572 0  433 Railroads and Related Services 0 1,037 576  435 Motor Freight Transportation and Warehousing 798 2,059 558  436 Water Transportation 0 2,006 1,248  437 Air Transportation 83 223 45  447 Wholesale Trade 1,601 9,607 4,804  482 Miscellaneous Repair Shops 6,395 12,790 2,132 

TOTAL 8,877 32,542 56,958 

Lay Seafloor Tie-back 251 Mineral Wool 0 16 220 Pipeline 311 Construction Machinery and Equipment 0 5,815 94,492 

 317 Industrial Trucks and Tractors 0 63 876  384 Motor Vehicles 0 87 1,214  386 Motor Vehicle Parts and Accessories 0 30 418  392 Ship Building and Repairing 0 7,386 1,970  393 Boat Building and Repairing 0 1,763 470  433 Railroads and Related Services 0 1,451 893  435 Motor Freight Transportation and Warehousing 1,047 2,581 935  436 Water Transportation 0 2,754 2,180  437 Air Transportation 252 707 80  447 Wholesale Trade 2,706 16,234 8,117  482 Miscellaneous Repair Shops 8,789 17,578 2,930 

TOTAL 12,794 56,463 114,795 
APPENDIX TABLE A-6

Capital Expenditures Per Activity Unit† by Activity, Region and IMPLAN Sector

IMPLAN

Activity Sector Description NSB Other AK Other US 

Land Base Operations 251 Mineral Wool 0 300 4,196 

 311 Construction Machinery and Equipment 0 9,204 128,853  315 Conveyors and Conveying Equipment 0 1,099 15,381  316 Hoists, Cranes, and Monorails 0 2,197 30,761  317 Industrial Trucks and Tractors 2,444 5,455 42,145  384 Motor Vehicles 0 5,596 78,339  386 Motor Vehicle Parts and Accessories 0 568 7,958  387 Truck Trailers 0 560 7,839  433 Railroads and Related Services 0 33,214 4,392  435 Motor Freight Transportation and Warehousing 10,466 28,719 4,463  436 Water Transportation 0 22,105 12,724  437 Air Transportation 1,237 3,359 586  447 Wholesale Trade 12,136 72,814 36,407  482 Miscellaneous Repair Shops 41,045 82,089 13,682 

TOTAL 67,327 267,278 387,726 

Spill Contingency 219 Fabricated Rubber Products, N.E.C. 0 17,747 0 

 338 General Industrial Machinery, N.E.C. 0 189,400 0  392 Ship Building and Repairing 0 46,300 0  393 Boat Building and Repairing 0 42,947 0  433 Railroads and Related Services 000 435 Motor Freight Transportation and Warehousing 1,354 4,063 0  436 Water Transportation 0 300 0  437 Air Transportation 76 228 0  447 Wholesale Trade 1,592 9,550 4,775  482 Miscellaneous Repair Shops 000

TOTAL 3,022 310,535 4,775 
APPENDIX TABLE A-6

Capital Expenditures Per Activity Unit† by Activity, Region and IMPLAN Sector

IMPLAN

Activity Sector Description NSB Other AK Other US 

†Activity Units

 Units Per 

Activity Units Year 

Barge Support 1 Day 120 Camp Support 1 Year 1 Drill Ship – Calm Water 1 Day 270 Drill Ship – Rough Water 1 Day 270 Equip Production Island 1 Island 1 Exploration Well 1 Well 3 Gravel Island 1 Island 1 Helicopter Support 1 Day 365 Ice Island 1 Island 1 Ice Road 10-Miles 1 Land Base Operations 1 Year 1 

 UActivity Units Mobile Bottom Founded Structure 1 Day Move Platform 1 Day Offshore Pipeline 1 Mile Onshore Pipeline 1 Mile Personnel Transport 1 Day Production Operations 1 Year Production Well 1 Well Seafloor Tieback Pipeline 10 Miles Seismic Survey 1 Month Spill Contingency 1 Year Well Work-over 1 Well 
Jack Faucett Associates ? 632/Final Report March 2003

DOI-MMS Arctic IMPAK

APPENDIX B: TOTAL REQUIREMENTS
Jack Faucett Associates - 632/Final Report March 2003

DOI-MMS Arctic IMPAK

Exhibit B-1 summarizes total per unit costs by activity and region. Please note that due to the

way in which the vectors were constructed, such totals are not directly comparable to cost

estimates obtained outside of this effort. For example, JFA developed cost vectors for camp

support, personnel transport and other secondary activities separately from those developed for

the main activity vectors in IMPAK. Such expenditures, however, are likely to be incorporated

in outside cost estimates of these main activities. To corroborate the results produced by the

model, the user is advised to draw upon the "TotalExpenditure" graph in the model. This graphic 

presents the temporal profile of total expenditures required for a given E&D scenario. Taking

into account differences in activity levels and combining various units of analysis, this aggregate 

estimate will be more accurate and more readily comparable to outside estimates than IMPAK's

per-unit estimates at the activity level. Note that the totals in the graph do exclude foreign

purchases, which are assumed to be a relatively small percent of total expenditures.

The table does not provide savings and government tax revenues per activity unit. IMPAK 

estimates these figures based upon total activity levels, as opposed to a per-unit basis. For a 

given E&D scenario, savings can be obtained on the output screen for each region. NSB 

Government Revenues are presented on the NSBLocalOutput screen and the accompanying 

graph (NSBGovRevenueGraph).

In Exhibit B-2, domestic business expenditures are itemized by activity, region, major cost 

category (e.g., capital, labor and materials), and IMPLAN sector.
Personal Total Personal Total Personal Total Personal Total 

Intermediate Consumption Total Personal Intermediate Consumption Total Personal Intermediate Consumption Total Personal Intermediate Consumption Total Personal Fo

Activity Purchases Expenditures Expenditures Income Purchases Expenditures Expenditures Income Purchases Expenditures Expenditures Income Purchases Expenditures Expenditures Income Purc

Seismic Survey 0 82,915 82,915 119,576 257,086 n.a. 257,086 n.a. 395,609 568,698 964,307 698,413 640,751 129,910 770,660 165,059 1Construct Ice Island 0 70,684 70,684 106,180 77,691 n.a. 77,691 n.a. 117,891 270,115 388,006 321,749 141,143 58,975 200,118 74,932 Drill Exploration Well 0 192,274 192,274 265,489 410,803 n.a. 410,803 n.a. 1,361,459 1,802,404 3,163,864 2,236,442 1,158,262 558,713 1,716,975 709,882 3Construct Gravel Island (Place Gravel) 0 178,288 178,288 247,552 464,539 n.a. 464,539 n.a. 617,352 1,786,355 2,403,707 2,219,673 730,976 316,578 1,047,555 402,234 Construct Gravel Island (Protect Island) 0 663,348 663,348 967,990 1,256,428 n.a. 1,256,428 n.a. 2,467,687 4,146,451 6,614,138 5,072,791 3,064,996 730,412 3,795,408 928,037 Install Production Modules 0 1,015,493 1,015,493 1,455,581 953,510 n.a. 953,510 n.a. 48,021,889 7,388,568 55,410,457 9,093,616 39,777,715 1,727,423 41,505,138 2,194,807 18,0Drill Production Well 0 64,091 64,091 88,496 143,916 n.a. 143,916 n.a. 663,670 600,801 1,264,472 745,481 598,445 186,238 784,683 236,627 3Operate Production Island 0 1,068,869 1,068,869 1,491,738 910,130 n.a. 910,130 n.a. 6,772,857 9,792,204 16,565,061 12,140,293 5,303,772 2,337,250 7,641,022 2,969,633 Construct Trenched Offshore Pipeline 0 241,980 241,980 326,714 665,558 n.a. 665,558 n.a. 2,655,047 2,766,121 5,421,168 3,448,540 5,946,749 670,592 6,617,341 852,032 1,1Construct Onshore Pipeline 0 138,831 138,831 187,134 712,874 n.a. 712,874 n.a. 5,256,116 1,602,538 6,858,654 1,998,328 6,135,241 388,739 6,523,980 493,919 1,2Well Workover 0 8,546 8,546 11,800 11,328 n.a. 11,328 n.a. 48,787 80,107 128,894 99,397 35,863 24,832 60,694 31,550 Landbase Operations 0 4,991,181 4,991,181 7,022,709 24,748,277 n.a. 24,748,277 n.a. 14,873,982 42,727,940 57,601,922 52,869,994 17,561,084 10,337,770 27,898,854 13,134,832 1Spill Contingency Operations 0 947,046 947,046 1,313,535 597,935 n.a. 597,935 n.a. 3,298,617 9,084,877 12,383,493 11,277,586 3,354,810 2,176,132 5,530,942 2,764,922 Abandonment 0 1,180,811 1,180,811 1,669,396 756,918 n.a. 756,918 n.a. 1,988,418 9,747,470 11,735,887 12,047,565 1,686,700 2,306,384 3,993,084 2,930,417 Construct Ice Road 0 111,273 111,273 166,518 124,067 n.a. 124,067 n.a. 190,755 456,590 647,346 546,489 230,694 101,308 332,002 128,719 Helicopter Support 0 216 216 294 1,029 n.a. 1,029 n.a. 1,094 2,595 3,689 3,238 997 311 1,308 395 Barge Support 0 103 103 139 589 n.a. 589 n.a. 1,532 1,265 2,798 1,580 2,483 225 2,708 285 Calm Water Drill Ship 0 1,221 1,221 1,682 5,846 n.a. 5,846 n.a. 40,830 12,309 53,139 15,300 14,628 2,959 17,587 3,760 Rough Water Drill Ship 0 5,679 5,679 7,814 39,507 n.a. 39,507 n.a. 97,266 57,616 154,883 71,627 56,692 13,857 70,550 17,607 Operate MBFS 0 1,173 1,173 1,615 33,602 n.a. 33,602 n.a. 169,386 11,859 181,245 14,741 33,592 2,852 36,444 3,623 Lay Seafloor Tie-back Pipeline 0 308,080 308,080 398,676 3,072,087 n.a. 3,072,087 n.a. 4,969,855 4,384,947 9,354,801 5,490,829 6,499,734 1,076,094 7,575,828 1,367,250 1,1Move Drill Ship/MBFS 0 5,679 5,679 7,814 3,664 n.a. 3,664 n.a. 136,524 57,616 194,140 71,627 47,695 13,857 61,553 17,607 General Personnel Transport 0 289 289 412 405 n.a. 405 n.a. 859 1,988 2,846 2,443 581 715 1,296 909 Camp Support 0 294,470 294,470 423,462 2,375,646 n.a. 2,375,646 n.a. 2,127,194 2,166,118 4,293,312 2,666,651 1,886,908 390,885 2,277,793 496,646 1NSB Government 0.52 0.27 0.79 0.30 0.00 n.a. 0.00 n.a. 0.09 0.03 0.12 0.00 0.09 0.00 0.09 0.00 Alaska State Government 0.00 0.00 0.00 0.00 0.00 n.a. 0.00 n.a. 0.61 0.30 0.91 0.30 0.09 0.00 0.09 0.00 Federal Government 0.00 0.00 0.00 0.00 0.00 n.a. 0.00 n.a. 0.00 0.00 0.00 0.00 0.70 0.30 1.00 0.30 TAPS 0 0 0 0 0.1 n.a. 0 n.a. 1 0 0.9 00000 Purchase MBFS 00000 n.a. 0 n.a. 168,150,000 0 168,150,000 0 44,840,000 0 44,840,000 0 23,0

6772857.016

Appendix Table B-1: Expenditures Per Activity Unit† by Region and Activity

NSB Local NSB Oil Economy Alaska US 

†Activity Units

 Units Per 

Activity Units Year 

Barge Support 1 Day 120 Camp Support 1 Year 1 Drill Ship – Calm Water 1 Day 270 Drill Ship – Rough Water 1 Day 270 Equip Production Island 1 Island 1 Exploration Well 1 Well 3 Gravel Island 1 Island 1 Helicopter Support 1 Day 365 Ice Island 1 Island 1 Ice Road 10-Miles 1 Land Base Operations 1 Year 1 

 Units Per Activity Units Year Mobile Bottom Founded Structure 1 Day 270 Move Platform 1 Day 270 Offshore Pipeline 1 Mile 1 Onshore Pipeline 1 Mile 1 Personnel Transport 1 Day 365 Production Operations 1 Year 1 Production Well 1 Well 9 Seafloor Tieback Pipeline 10 Miles 1 Seismic Survey 1 Month 4 Spill Contingency 1 Year 1 Well Work-over 1 Well 30