OCS Study 

MMS 2006-064 

 

Coastal Marine Institute 

Capital Investment Decisionmaking 

and Trends: Implications on Petroleum 

Resource Development in the U.S. 

Gulf of Mexico 

Cooperative Agreement

Coastal Marine Institute 

Louisiana State University 

U.S. Department of the Interior

Minerals Management Service 

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

Minerals Management Service Coastal Marine Institute 

Gulf of Mexico OCS Region Louisiana State University 

OCS Study 

 MMS 2006-064 

Coastal Marine Institute 

Capital Investment Decisionmaking 

and Trends: Implications on Petroleum 

Resource Development in the U.S. 

Gulf of Mexico 

Authors 

Mark J. Kaiser 

Allan G. Pulsipher 

October 2006 

Prepared under MMS Contract 

1435-01-99-CA-30951-18178 

by 

Louisiana State University 

Center for Energy Studies 

Baton Rouge, Louisiana 70803 

Published by 
iii

DISCLAIMER

This report was prepared under contract between the Minerals Management Service 

(MMS) and Louisiana State University’s Center for Energy Studies. This report has been 

technically reviewed by MMS. Approval does not signify that the contents necessarily 

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

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

exempt from review and compliance with MMS editorial standards. 

REPORT AVAILABILITY 

Extra copies of the report may be obtained from the Public Information Office (Mail Stop 

5034) at the following address: 

 

 U.S. Department of the Interior 

 Minerals Management Service 

 Gulf of Mexico OCS Region 

 Public Information Office (MS 5034) 

 1201 Elmwood Park Boulevard 

 New Orleans, Louisiana 70123-2394 

 Telephone Number: 1-800-200-GULF 

 1-504-736-2519 

CITATION 

Suggested citation: 

Kaiser, M.J. and A.G. Pulsipher. 2006. Capital investment decisionmaking and trends: 

Implications on petroleum resource development in the U.S. Gulf of Mexico. 

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

Region, New Orleans, LA. OCS Study MMS 2006-064. 130 pp. 
v

ABSTRACT

Many factors impact the demand for and supply of oil and natural gas, influence how and 

where energy companies invest their capital, and determine the manner in which 

countries compete to attract foreign investment. World oil supply derives from the 

investment decisions of individual companies, the political decisions of countries in 

regard to licensing and degree of foreign investment, and a multitude of other variables 

that influence system dynamics, including price, inventory levels, geopolitics, market 

psychology and manipulation, OPEC policy, exchange rates, unexpected events, and 

resource availability. 

The purpose of this report is to examine the factors that impact the oil and gas exploration 

and capital markets. We begin with a general overview of the oil and gas industry and 

product demand and supply, provide background information on oil and gas resources, 

and describe the defining characteristics of exploration and capital markets. The factors 

that impact supply and demand, investment decisions, and country competitiveness are 

then reviewed. We conclude with a summary outline of the fiscal systems used in the 

exploration and production industry. 
vii

TABLE OF CONTENTS

Page 

LIST OF FIGURES ......................................................................................................... xiii 

LIST OF TABLES.............................................................................................................xv 

1. EXECUTIVE SUMMARY .....................................................................................1 

2. INDUSTRY CHARACTERISTICS........................................................................3 

 2.1. Business Functions.......................................................................................3 

 2.2. U.S. Upstream..............................................................................................3 

 2.3. U.S. Downstream.........................................................................................4 

 2.4. Business Characteristics...............................................................................4 

 2.5. Industry Structure.........................................................................................6 

 2.5.1. Integrated Oil Companies ................................................................6 

 2.5.2. Independents ....................................................................................6 

 2.5.3. National Oil Companies...................................................................6 

 2.6. Mergers and Acquisitions ............................................................................7 

 2.7. Corporate Strategies.....................................................................................7 

 2.8. Corporate Goals ...........................................................................................9 

 2.9. Capital Budgeting Process ...........................................................................9 

3. PRODUCT DEMAND AND SUPPLY.................................................................11 

4. OIL AND GAS RESOURCES ..............................................................................13 

 4.1. Fossil Fuels ................................................................................................13 

 4.1.1. Coal................................................................................................13 

 4.1.2. Crude Oil and Natural Gas.............................................................13 

 4.2. Market Value .............................................................................................14 

 4.3. Reserves and Resource Estimates..............................................................15 

 4.4. World Proved and Undiscovered Reserves................................................16 

 4.5. Unconventional Resources.........................................................................17 

 4.5.1. Heavy Oil.......................................................................................17 

 4.5.2. Tar Sands (Bitumen)......................................................................17 

 4.5.3. Oil Shale (Kerogen) .......................................................................17 

5. OIL AND GAS MARKETS ..................................................................................19 

 5.1. Oil and Gas Are Commodities...................................................................19 

 5.2. Prices Are Determined by Supply, Demand, and Inventory Conditions ...19 

 5.3. Crude Prices Exist in Many Forms ............................................................19 

 5.3.1. Benchmarks....................................................................................19 

 5.3.2. In-Situ vs. Wellhead Prices............................................................20 

 5.3.3. Spot Prices .....................................................................................20 
viii

TABLE OF CONTENTS

(continued) 

Page 

 5.4. Oil Supply and Demand Imbalance ...........................................................20 

 5.5. Oil Markets Are Global, Gas Markets Are Regional.................................20 

 5.6. Oil and Gas Prices Are Volatile.................................................................21 

 5.7. Price Spikes................................................................................................21 

6. DATA SOURCES, DATA QUALITY, AND PROBLEMS OF 

 INTERPRETATION..................................................................................23 

 6.1. Data Sources ..............................................................................................23 

 6.2. Data Quality...............................................................................................23 

 6.3. Problems of Interpretation .........................................................................24 

 6.3.1. Microeconomic vs. Macroeconomic Perspective ..........................24 

 6.3.2. Aggregation....................................................................................24 

 6.3.3. Omitted Variables ..........................................................................25 

 6.3.4. Factor Types...................................................................................25 

7. FACTORS THAT IMPACT SUPPLY AND DEMAND......................................27 

 7.1. Economic Activity .....................................................................................27 

 7.2. Inventory....................................................................................................28 

 7.3. Price ...........................................................................................................28 

 7.4. Geopolitics .................................................................................................28 

 7.5. Geology......................................................................................................29 

 7.6. Access to Reserves.....................................................................................29 

 7.7. Technology ................................................................................................30 

 7.8. Exchange Rates..........................................................................................30 

 7.9. Depletion (Existing Fields)........................................................................30 

 7.10. Discovery Rate (New Fields).....................................................................31 

 7.11. OPEC Policy ..............................................................................................31 

 7.12. Role of National Oil Companies................................................................31 

 7.13. Exceptional Events.....................................................................................32 

 7.14. Market Manipulation .................................................................................33 

 7.15. Government Policy ....................................................................................33 

 7.15.1. Licensing and Incentives................................................................33 

 7.15.2. Taxation .........................................................................................33 

 7.15.3. Fiscal Regime.................................................................................34 

 7.15.4. Environmental Regulations............................................................34 

 7.15.5. Conservation ..................................................................................34 

 7.16. Political Risk..............................................................................................34 
ix

TABLE OF CONTENTS

(continued) 

 Page 

8. FACTORS THAT IMPACT E&P INVESTMENT ..............................................35 

 8.1. Financial Performance ...............................................................................35 

 8.1.1. Dividend Strategy ..........................................................................35 

 8.1.2. Share Purchases .............................................................................36 

 8.1.3. Debt Reduction ..............................................................................36 

 8.2. Availability of Capital................................................................................36 

 8.3. Budget Allocation ......................................................................................36 

 8.4. Business Opportunities ..............................................................................36 

 8.5. Oil Price .....................................................................................................36 

 8.6. Oil Price Volatility.....................................................................................37 

 8.7. Merger and Acquisition Activity ...............................................................37 

 8.8. Debt/Equity Position..................................................................................37 

 8.9. Business Uncertainty .................................................................................38 

 8.10. Capacity Constraints ..................................................................................38 

 8.11. Resource Availability.................................................................................38 

 8.12. Risk Strategies ...........................................................................................39 

 8.13. Government Policy ....................................................................................39 

 8.14. Exogenous Variables .................................................................................39 

9. E&P EXPENDITURE TRENDS...........................................................................41 

 9.1. U.S. Major Energy Producers ....................................................................41 

 9.1.1. Return on Equity............................................................................42 

 9.1.2. Sources and Uses of Cash..............................................................42 

 9.1.3. Capital Expenditures......................................................................42 

 9.2. U.S. Independent Producers.......................................................................43 

 9.3. Capital Expenditures..................................................................................43 

 9.3.1. Data Source....................................................................................43 

 9.3.2. U.S. and Non-U.S. Capital Spending.............................................44 

 9.3.3. Worldwide Capital Spending.........................................................44 

 9.4. IEA Investment Forecast............................................................................45 

 9.5. Lifting Costs...............................................................................................45 

 9.6. Finding Costs .............................................................................................46 

10. IMPLICATIONS OF EXPECTATIONS ABOUT FACTORS AFFECTING 

 CAPITAL BUDGETING AND DECISION MAKING FOR THE 

 OCS GULF OF MEXICO .........................................................................47 

11. COUNTRY COMPETITIVENESS.......................................................................57 

 11.1. International Petroleum Arrangements......................................................57 

 11.2. Contract Types...........................................................................................58 

 
x

TABLE OF CONTENTS

(continued) 

Page 

 

 11.3. Exploration Market ....................................................................................58 

 11.4. Capital Market ...........................................................................................59

12. FISCAL SYSTEM FUNDAMENTALS ...............................................................61 

 12.1. Economic Rent...........................................................................................61 

 12.2. Oil Company and Host Government Objectives .......................................61 

 12.3. Fiscal Regime.............................................................................................61 

 12.4. A Brief History of International Arrangements.........................................62 

 12.5. Fiscal Systems Vary Over Time, Country, Region, and Field...................63 

13. FISCAL ELEMENTS............................................................................................65 

 13.1. Concessionary Systems..............................................................................65 

 13.2. Contractual Systems...................................................................................66 

14. LICENSING AND NEGOTIATION ....................................................................67 

15. FACTORS THAT IMPACT E&P CONTRACT STRUCTURE ..........................69 

 15.1. Categorization............................................................................................69 

 15.1.1. Geologic Prospectivity...................................................................69 

 15.1.2. Technical Prospectivity..................................................................69 

 15.1.3. Country Prospectivity ....................................................................69 

 15.1.4. Geopolitical Prospectivity..............................................................69 

 15.1.5. Legal Prospectivity ........................................................................69 

 15.2. Factor Description......................................................................................70 

 15.2.1. Reserves Additions ........................................................................70 

 15.2.2. R/P Ratio........................................................................................70 

 15.2.3. Finding and Development Cost .....................................................70 

 15.2.4. Country E&P History.....................................................................70 

 15.2.5. Industry Structure...........................................................................71 

 15.2.6. Economic Strength.........................................................................71 

 15.2.7. Economic Growth ..........................................................................71 

 15.2.8. Oil Price Risk.................................................................................71 

 15.2.9. Oil Intensity ...................................................................................71 

 15.3. Fiscal Systems Are Governed by Multiple Trade-Offs .............................71 

16. CONTRACT SELECTION ...................................................................................75 

 16.1. Data Source................................................................................................75 

 16.2. Categorization............................................................................................75 

 16.2.1. One Factor......................................................................................75 

 16.2.2. Two or More Factors .....................................................................76 
xi

TABLE OF CONTENTS

(continued) 

Page 

17. CONTRACT TERMS, CONDITIONS, COMPARISONS...................................79 

 17.1. Negotiating Contract Terms.......................................................................79 

 17.2. Measurement Issues...................................................................................79 

 17.3. Take Measure.............................................................................................80 

 17.3.1. Standard Field Conditions..............................................................80 

 17.3.2. Specific Field Conditions...............................................................80 

 17.4. Many Different Notions of Take Exist ......................................................80 

 17.4.1. Bid Submission ..............................................................................81 

 17.4.2. Negotiation and Award..................................................................81 

 17.4.3. Discovery .......................................................................................81 

 17.4.4. Production......................................................................................81 

 17.4.5. Abandonment.................................................................................81 

 17.5. Summary of Take Characteristics..............................................................81 

 17.6. Production Sharing Agreement Statistics ..................................................82 

REFERENCES ..................................................................................................................83 

APPENDIX—TABLES AND FIGURES .........................................................................91 
xiii

LIST OF FIGURES

Figure Description Page

A.1 Estimated Petroleum Consumption by Sector, 1949-2004............................119 

A.2 Estimated Petroleum Consumption – Residential and Commercial 

 Sectors, 1949-2004 ..................................................................................119 

A.3 Estimated Petroleum Product Consumption – Industrial Sector, 

 1949-2004 ................................................................................................120 

A.4 Estimated Petroleum Product Consumption – Transportation Sector, 

 1949-2004 ................................................................................................120 

A.5 Estimated Petroleum Consumption – Electric Power Sector, 1949-2004 .....121 

A.6 Production, Consumption, and Net Imports of Crude Oil, 1949-2004..........121 

A.7 Refinery Input, 1949-2004.............................................................................122 

A.8 Refinery Output, 1949-2004 ..........................................................................122 

A.9 World Nominal Oil Price Chronology...........................................................123 

A.10 Crude Oil Refiner Acquisition Costs and Refiner Sales Prices for 

 Selected Petroleum Products, 1988-2004 ................................................124 

A.11 Average Return on Investment by Industry, 1993-2002................................125 

A.12 Volatility of Return on Investment by Industry, 1993-2002..........................125 

A.13 Return on Stockholder’s Equity for FRS Companies and the S&P 

 Industrials, 1973-2004 .............................................................................126 

A.14 Return on Net Investment for U.S. and Foreign Oil and Gas Production, 

 1977-2004 ................................................................................................126 

A.15 Cash Flow from Operations and Exploration and Production Expenditures 

 for FRS Companies..................................................................................127 

A.16 Worldwide Expenditures for Exploration, Development, and Production 

 for FRS Companies..................................................................................127 

A.17 FRS Expenditures for Oil and Natural Gas Exploration by Region, 

 1995-2004 ................................................................................................128 

A.18 FRS Expenditures for Oil and Natural Gas Development by Region, 

 1995-2004 ................................................................................................129 

A.19 Direct Oil and Gas Lifting Costs for FRS Companies, 1981-2004 ...............129 

A.20 U.S. Onshore, U.S. Offshore, and Foreign Three-Year Weighted-Average 

 Finding Costs for FRS Companies, 1981-1983 to 2002-2004.................130 
xv

LIST OF TABLES

Table Description Page 

1 Factors that Impact Supply and Demand.........................................................48 

2 Factors that Impact E&P Investment ...............................................................51 

A.1 Various Risks Exist in Oil and Gas Investment...............................................93 

A.2 Examples of Integrated Companies Classified According to Geographic 

 Operation....................................................................................................93 

A.3 Examples of Independent Companies Classified According to Size and 

 Geographic Operation................................................................................94 

A.4 Selected National Oil Companies ....................................................................95 

A.5 Top 10 Oil and Gas Company Rankings – Oil (2006).....................................96 

A.6 Top 10 Oil and Gas Company Rankings – Oil & Gas (2006) .........................96 

A.7 Percentage Yields of Refined Petroleum Products from Crude Oil in the 

 U.S., 1964-2003 (%) ..................................................................................97 

A.8 U.S. Proven Reserves and Undiscovered Resources .......................................97 

A.9 World Proven Reserves and Undiscovered Resources ....................................97 

A.10 World Proven Reserves (2004) and Undiscovered Resources (2000).............98 

A.11 World Proved Oil Reserves (2004)..................................................................99 

A.12 World Undiscovered Oil Resources, 2000 (Thousand Million Barrels)........100 

A.13 World Proved Natural Gas Reserves (2004)..................................................101 

A.14 World Undiscovered Natural Gas Resources, 2000 (Trillion cubic feet)......102 

A.15 Bitumen (Tar Sands) and Heavy Oil Technically Recoverable Resources 

 (2003).......................................................................................................103 

A.16 Oil Production and Consumption Among Primary Producing Countries 

 (2004).......................................................................................................104 

A.17 OPEC Production Quotas (Million Barrels per Day) ....................................105 

A.18 World Oil Supply Disruptions .......................................................................105 

A.19 Sources and Uses of Cash for FRS Companies, 2003-2004 

 (Current Billion Dollars)..........................................................................106 

A.20 Exploration and Development Expenditures by Region for FRS 

 Companies, 1998-2004 (Current Million Dollars)...................................107 

A.21 Representative Global Upstream Oil and Gas Investment Comparison........108 

A.22 U.S. Capital Spending, 1994-2003 (Current Million Dollars).......................109 

A.23 Worldwide Petroleum Industry Capital Spending, 1990-2001 

 (Current Million Dollars).........................................................................110 

A.24 Lifting Costs by Region for FRS Companies, 2003-2004 (2004 Dollars 

 Per Barrel of Oil Equivalent) ...................................................................111 

A.25 Finding Costs by Region for FRS Companies, 2001-2003 and 2002-2004 

 (2004 Dollars Per Barrel of Oil Equivalent)............................................111 

A.26 The Prospectivity of a Region Is Influenced by Many Factors .....................112 

A.27 Hydrocarbon Net Exporting Countries Oil and Natural Gas Exports and 

 Fiscal Revenues in 2003 ..........................................................................113 

 
xvi

LIST OF TABLES

(continued) 

Table Description Page 

A.28 One Factor, Two Dimensional Contract Classification .................................114 

A.29 One Factor, Five Dimensional Contract Classification .................................114 

A.30 Multi-Dimensional Contract Classification ...................................................114 

A.31 Two Factor, Four Dimensional Contract Classification ................................115 

A.32 Representative Contract Terms and Government Take.................................116 

A.33 The Notion of Take Changes Throughout the Life of a Prospect..................117 

A.34 Trends in PSA Contract Terms......................................................................118 
1

1. EXECUTIVE SUMMARY

The demand for oil and gas begins at the individual and corporate level. Individuals drive 

cars, heat and cool their homes, and consume food and other services, all of which 

require – either directly or indirectly – oil, gas, and petroleum-derived products. Industry 

provides goods and services that require energy to function. 

Many factors impact the demand for and supply of oil and natural gas, influence how and 

where energy companies invest their capital, and determine the manner in which 

countries compete to attract foreign investment. The relationship between the various 

factors and their relative importance is subject to interpretation, argument and debate. 

World oil supply derives from the investment decisions of individual companies, the 

political decisions of countries in regard to licensing and degree of foreign investment, 

and a multitude of exogenous variables that influence system dynamics, including price, 

inventory levels, geopolitics, market psychology and manipulation, OPEC policy, 

exchange rates, unexpected events, and resource availability. 

The purpose of this report is to examine the factors that impact the oil and gas exploration 

and capital markets. We begin with a general overview of the oil and gas industry and 

product demand and supply, provide background information on oil and gas resources, 

and describe the defining characteristics of exploration and capital markets. The factors 

that impact supply and demand and investment decisions are then reviewed. We then use 

this information to relate “conventional expectations” concerning these factors to future 

investment trends in the Gulf of Mexico. The “conventional expectation” is a subjective 

characterization by the authors of the perceptions, opinions, and analysis prevailing 

among those that follow the oil and gas industry. We conclude with a summary outline of 

the fiscal systems used in the exploration and production industry. 
3

2. INDUSTRY CHARACTERISTICS

2.1. Business Functions 

Oil and gas companies may be involved in several different types of functions: 

• Exploration, development, and production, 

• Transportation, 

• Refining, 

• Marketing and distribution, and 

• Petrochemicals. 

The “upstream” segment of the business refers to exploration and production (E&P) 

activities; refining and marketing is “downstream,” and transportation is the “midstream” 

segment of the business. 

Companies which operate in all segments of the industry are fully integrated, while 

companies that operate in one or more but not all segments are called partially integrated 

or independents. An independent oil producer, for instance, is primarily involved in only 

E&P; an independent refiner is involved primarily in refining. The largest integrated oil 

companies are referred to as majors or supermajors. Various other categorizations are 

also frequently used, such as international integrated, U.S. integrated, large independents, 

small independents, etc. based on market capitalization, proved reserves, and related 

criteria. 

2.2. U.S. Upstream 

 

A large number of independent producers and a smaller number of fully integrated 

companies characterize the U.S. upstream. According to the Energy Information 

Administration (EIA), in 2001 there were 179 large1 operators in the United States, which 

accounted for 84.2% crude oil production; 430 intermediate operators, which accounted 

for 5.8% production; and 22,519 small operators, which accounted for 10% production. 

In the U.S. offshore industry, 319 working interest owners were reported2

 in the Gulf of 

Mexico at the end of 2003. The vast majority of companies in the Gulf of Mexico are 

small, independent firms, but just 21 companies hold the majority of production 

responsible for over 80% of 2003 production (Kaiser and Pulsipher, 2006). The top four 

producing companies (Shell, Chevron, BP, ExxonMobil) are responsible for over 40% 

total Gulf of Mexico hydrocarbon production. 

 

 

1

 The EIA defines large operators as producing a total of 1.5 million barrels or more of crude, 15 billion 

cubic feet of natural gas, or both; intermediate operators as producing at least 400,000 barrels of oil, 2 

billion cubic feet of gas, or both, but less than the large operators; and small operators as producing less 

than the intermediate operators. 

2

 The collection of owners and asset holdings are constantly in flux, and so the data reported represents a 

“snapshot” of conditions that exist relative to the year 2003. 
4

2.3. U.S. Downstream 

The structure of the refining industry has undergone significant change over the past 

decade. Once led by a half-dozen vertically integrated majors, the industry is now 

characterized by a handful of super-majors and an array of mid-size and small 

independents focused on refining and marketing within specific regions and product 

lines. Independent refiners and marketers are typically only involved in downstream 

activities. The traditional industry model of refining, based on ownership by vertically 

integrated oil companies and profitability viewed within the context of a linked supply 

chain, has been replaced by refineries operated in a stand-alone profit center mode. 

Before 1980, nearly all U.S. refineries were held by integrated oil companies, while 

today, ownership structure is more diverse and concentrated. In 2005, the top three U.S. 

refiners processed 36% of total crude oil; the top 10 refiners processed 77%; and the top 

20 refiners processed 92% (API, 2005). Independents currently own about 64% of U.S. 

refining capacity versus 51% in 1990. Foreign ownership has risen from 19% of total 

capacity in 1990 to about 25% in 2005. Royal Dutch Shell, BP, Total, Saudi Aramco, and 

Petroleos de Venezuela SA are major foreign owners of U.S. refining capacity. 

The majority of distillation capacity is currently concentrated in large, integrated 

companies with multiple refining facilities. Fifty-five firms, ranging in size from 880 

barrels per day (BPD) to a combined refinery capacity of 1.8 million BPD comprise the 

industry (EIA, 2005). About two thirds of firms are small operations producing less than 

100,000 BPD and representing about 5% of the total output of petroleum products. Large 

refiners often manage both large and small refineries, while small operators mainly 

specialize in asphalt, lubricants, and other niche products. Integrated firms such as 

ConocoPhillips, ExxonMobil, BP, and Chevron maintain a global portfolio of petroleum 

assets. Independent companies like Valero and Sunoco focus primarily on domestic 

refining, although they may also be involved in marketing and other operations. Several 

joint ventures and partnerships also exist. 

2.4. Business Characteristics 

The oil and gas industry is characterized by a number of unique conditions: 

• High capital intensity, 

• High level of risk, 

• Complex tradeoffs between capital and operating expenditures, 

• Long time span before a return on investment is received, 

• Lack of correlation between the magnitude of expenditures and the value of 

any resulting reserves, 

• High level of regulation, 

• Complex tax rules, 

• World’s largest corporations, 

• High level of competition, and 

• Complex industry structure. 
5

Oil and gas exploration and development is a high risk, capital intensive business. 

Finding oil and natural gas throughout most of the world is difficult, costly, and 

uncertain. The cost of obtaining leases and conducting exploratory work requires an 

enormous investment before reserves are quantified and economic viability ensured. 

The expenditure of millions and sometimes billions of dollars is required for a single 

project, with no guarantees on the success of the outcome. Investment, in its most basic 

form, is paying now for the purpose of a reward later. Particularly in oil and gas ventures, 

however, there are risks of various kinds that need to be considered. Does oil exist in the 

region? If reserves are found are they smaller than expected or decline faster than 

geologic conditions suggest? The quality and quantity of the resource is uncertain 

because it exists deep underground in heterogeneous rock formations, and as a deposit is 

produced, the cash flows are subject to various forms of uncertainty and risk (Table A.1). 

Will drilling lead to a blow-out? What is the probability of an earthquake, mudslide, or 

hurricane destroying the facilities? Will oil prices remain strong or nose-dive? How will 

inflation rates behave? Will the government try to renegotiate the terms of the contract at 

a later date? Is nationalization a risk? 

 

Risks arise from the project (construction, operation, production, reserve), as well as 

changes in global economic conditions (market, macroeconomic), political circumstances 

(regulatory, expropriation), legal conditions (contract, jurisdictional), and force majeure 

(natural disaster, civil unrest, terrorism). The higher the risk associated with an 

investment, the higher the cost of capital and the higher the return required by investors 

and lenders (Grayson, 1960). 

After a well is drilled, the reservoir drive pushing the oil to the surface will progressively 

exhaust itself if no additional investment is made (Dyke, 1997). To produce at a high rate 

of extraction requires more wells, greater production and storage facilities, and greater 

transportation capacity. A complex trade-off exists between producing “fast” (large 

number of wells, high capital expenditures) or “slow” (fewer wells, low capital 

expenditures). 

The long-lived nature and high capital cost and risk characteristic of E&P projects result 

in a long payout period, and due to the nature of the resource and project life cycle, there 

is generally a significant time delay between the magnitude of expenditure and the value 

of the reserves. This time delay results in significant problems in accounting for oil and 

gas operations, as well as measuring performance, because there is no direct correlation 

between the magnitude of expenditures and the value of reserves (Gallun et al., 2001). 

The oil and gas industry is large with some of the world’s largest corporations. In the 

U.S., 29 major energy companies in 2004 reported operating revenues of $1.13 trillion, 

equal to about 15% of the $7.4 trillion in revenues of the Fortune 500 corporations (U.S. 

Energy Information Administration, 2005). 

The structure of the oil and gas industry is dynamic and highly competitive. Majors, 

independents, and National Oil Companies (NOCs) each have different business models, 
6

corporate governance, shareholder expectation, and outlooks of the industry, and all vie 

for access to resources. Oil and gas companies have a vast intellectual capital, but it has a 

peculiar limitation, since it has no value unless applied in the exploration and production 

of oil and gas. 

 

2.5. Industry Structure 

2.5.1. Integrated Oil Companies: Major integrated firms such as BP, Chevron, 

ExxonMobil, Royal Dutch Shell, and Total tend to seek opportunities on a worldwide 

basis with large upsides to deploy their management, financial, and technical skills. 

Majors specialize in managing complex, multifaceted and technically challenging 

ventures, and seek projects that help balance their portfolio of assets. Capital is allocated 

to areas on a risk-reward basis within the constraints of maintaining a balanced portfolio 

of projects. 

Integrated firms with a geographic specialization are shown in Table A.2 and include 

U.S. producers (e.g., Amerada Hess, ConocoPhillips, Murphy Oil), Canadian producers 

(e.g., Husky, Imperial Oil, Suncor), and international firms which do not have a large 

presence in North America but are active elsewhere throughout the world (e.g., ENI, 

Lukoil, Petrobras, Petrochina, Statoil). 

2.5.2. Independents: Independents seek prospects across a wide range of opportunities: 

from modest to marginal reserves, high to low risk projects, regional and global locations. 

Examples of independent companies classified according to size and geographic 

operation are depicted in Table A.3. Independents usually have lower overhead than 

majors, can act quickly on strategic opportunities, and tend to have an entrepreneur flair. 

Independents may seek to grow in reserves or capital, and may transition across 

categories depending upon their business objectives, merger and acquisition strategies, 

and other factors. 

2.5.3. National Oil Companies: The role of NOCs is arguably the most important 

factor in the future of the industry. NOCs control the majority of oil and gas reserves 

known in the world and demand-side NOCs are becoming more active competitors in 

world markets. A list of selected NOCs is provided in Table A.4. 

State-owned companies are generally formed to maximize revenue from state resources. 

Governments use NOCs for many different national objectives, however, from resource 

custodian, securer of supply, revenue collector, or engine of national development. 

National Oil Companies have broader constraints and obligations than private 

corporations, basing their decisions on domestic, geopolitical, as well as economic 

factors. 

Not all NOCs are created equal. National Oil Companies can be classified in a number of 

ways, such as in terms of their degree of privatization (state monopolies, partial 

privatization, full privatization), resource ownership (resource holders [supply-side 

companies] vs. resource seekers [demand-side companies]), country/business 
7

characteristics (GDP per capital, economic strength, corruption index, reserves), strategic 

priorities (revenue growth, security of supply, profit/margin, local economic 

development, international/diplomatic relations, infrastructure development), etc. 

Demand-side NOCs are changing the nature of competition, offering supply-side NOCs 

strategic partnerships that extend to economic and infrastructure development. The 

political alignment between nations and their oil companies can bring a distinct 

competitive advantage, which will further increase competition for multinational 

companies in acquiring investment opportunities. 

In terms of reserves, over 90% of the proved oil reserves in the world are under direct or 

partial state ownership, primarily in the Middle Eastern OPEC countries. The top 10 oil 

and gas company rankings by reserves and production for oil (Table A.5) and oil and gas 

(Table A.6) illustrates the absolute strength of NOCs. PFC Energy estimates that 65% of 

the world’s proven oil and gas reserves are controlled by governments not open to 

western companies; 16% proven reserves are held by Russian companies; 12% by 

governments with limited access for investment; and 7% with full access (Ball, 2006). 

 

2.6. Mergers and Acquisitions 

Mergers and acquisitions in the oil and gas industry occur for various reasons, generally 

related to the need for increased efficiency and cost savings (U.S. General Accounting 

Office, 2004), and increasingly, the need to compete with demand-side NOCs and offer 

synergies with international partners. Merger and acquisition activity may also be driven 

by the desire or need to diversify assets, enhance stock values, and respond to price 

volatility. From 1991-2000, over 2,600 merger transactions occurred in the oil industry 

(U.S. General Accounting Office, 2004). The vast majority of the mergers 

(approximately 85% of the total) occurred in the upstream segment, involving one 

company purchasing an asset from another company, such as a refinery, pipeline, or 

producing properties. The downstream segment accounted for about 13% of the mergers; 

the midstream segment about 2%. The majority of the reported transaction values were 

below $50 million, and over 89% of these mergers were asset transactions. About 32% of 

the mergers exceeded $50 million and 3% were over $1 billion. 

2.7. Corporate Strategies 

 

There are many strategies that a company may pursue in exploration, development, and 

production activities. The basic strategy that a company adopts, and the factors that drive 

the selection, provides information on the way companies do business and view the 

outlook of their industry. Strategies for public companies are frequently disclosed at 

investor and Board of Director meetings and can be inferred from annual reports, whereas 

strategies for NOCs may not be articulated or known outside the company. The diversity 

and depth of strategies that exist in the industry is significant, and no categorization is 

sufficiently descriptive to encompass all possible cases. Categories may change as 

internal (staffing, assets, successes, failure, etc.) and external (oil price, markets, interest 

rates, etc.) circumstances are played out. 

 
8

For the purposes of discussion, we apply the following classification: 

 

• No specialty, 

• Geographic specialty, 

• Technological specialty, 

• Low cost specialty, and 

• Risk specialty. 

Companies may specialize within a single category or simultaneously pursue projects that 

fall within two or more categories. No specialty strategies are commonly carried out by 

the large integrated companies to help ensure that failure in one or more areas is 

compensated by success elsewhere. Oil and gas companies that hold geographically 

diverse assets across all parts of the supply chain are less vulnerable to specific events 

than companies that hold assets in one part of the supply chain in one geographic region. 

Breadth of operations allows companies to reduce the volatility of their return on 

investment and reduce their cost of capital. Integrated oil and gas companies tend to have 

lower volatility of their return on investment than independent companies. 

Geographic specialization allows a company to minimize overhead expense and develop 

a regional expertise which may lead to reduced drilling and development cost in the 

region. Each country provides different opportunities for investment which depend on 

technical, economic, and political factors; the core competencies of the company and 

their strategic goals; and specific geopolitical and socioeconomic circumstances. One of 

the downsides of geographic specialization is that it restricts upside potential when 

reserves begin to decline, but specialization also allows a high degree of learning 

economies. Most independent operators in the U.S. offshore, Pemex (Mexico), and 

several NOCs fall within this group. 

 

Technological specialization may take various forms and allow companies to capitalize 

on in-house technical strengths or to specialize in specific areas such as onshore/offshore, 

shallow water/deepwater, oil/gas, geologic and working interest plays, and mature assets. 

Low cost strategies allow companies to explore without large financial backing and to 

farm out acreage after adding value to the asset, or to purchase marginal (end-of-life) 

property for production and acreage opportunities. 

Risk strategies involve confining activities to ventures that have a defined risk-reward 

level. High risk projects are expected to have high rewards, low initial cost, and low 

government take. Low risk projects are more likely to occur in proven producing areas 

and will have lower rewards because of less favorable government terms and smaller 

available prospects. 

 
9

2.8. Corporate Goals 

The three primary objectives of every corporation are to: 

• Increase its equity appreciation (total worth) to survive and grow, 

• Control the total cash flow within, into, and out of the corporation, and 

• Maintain or increase some form of dividends to shareholders. 

To accomplish these tasks, the company must receive an average positive rate of return 

on its portfolio of investments. Since projects and investments appear as cash flows, the 

control of cash usually has some form of corporate decision rules and procedures 

(Lerche, 1992). The criteria to give a dividend, repurchase shares, or invest in projects are 

the capital budgeting decision. 

2.9. Capital Budgeting Process 

Budgeting is practiced by all public, private, and National Oil Companies, but because of 

its encompassing nature, a standardized definition does not exist. A budget is usually 

considered the principal management vehicle for the expression of a company’s plans and 

objectives for a specified period of time (normally twelve months). 

 

A capital budget is a fixed asset spending plan which in the oil industry tend to occur on a 

project-by-project basis. A profitable3

 oil company is the combination of profitable 

projects, and since each project has a different risk-reward strategy, oil companies try to 

build a diversified portfolio to maximize the return to their shareholders. 

The typical capital budgeting process follows three steps: 

1. Identify all non-discretionary (mandatory) capital expenditures; e.g., new 

government regulations, corporate policy, previously initiated projects. 

2. Establish the level of funds available for discretionary expenditure. 

3. Select investments in descending order of rank until either the total available 

funds are exhausted or the minimum acceptable yard stick value reached. 

Each step will vary from one organization to another with various techniques and criteria 

employed in ranking investment opportunities. Large organizations tend to rank 

investments using different criteria and emphasis than smaller companies. The volume 

and quality of investment opportunities, and the immediate cash position of the 

organization, also impact the way the rankings are perceived and ranked. 

 

3 The Royal Dutch Shell statement of general business principles is standard: 

“Profitability ... is essential for the proper allocation of corporate resources and necessary to 

support the continuing investment required to develop and produce future energy supplies... The 

criteria for investment decisions are essentially economic, but also take into account social and 

environmental considerations and an appraisal of the security of the investment.” 
10

The criteria that are typically used in ranking investment opportunities include payback, 

net present value, discounted return on investment, internal rate of return, and profit on 

investment (Wehrung, 1989). The investment opportunities are graded according to the 

criteria which reflects the goals and strategies of the organization. 
11

3. PRODUCT DEMAND AND SUPPLY 

Over the past two decades, the demand for petroleum products in the U.S. has risen 

steadily, due in part to a growing population, falling fuels prices, Americans’ preference 

for heavier and more powerful vehicles, and an increase in passenger and goods travels. 

In 2005, daily demand for refined products in the U.S. was about 21 million barrels, 

equivalent to a consumption rate of about 20 pounds of petroleum per person per day. No 

other commodity in the history of the world has ever been consumed at such levels. 

In 2005, the U.S. consumed about 14 million barrels per day (BPD) in the transportation 

sector, 4 million BPD in the industrial sector, 2 million BPD in the residential and 

commercial sector, and 1 million BPD in the electric power sector (Figure A.1). 

Consumption trends by sector for refined products are shown in Figure A.2-A.5. 

The U.S. demand for crude oil and petroleum products exceeds its supply (Figure A.6), 

and so the U.S. imports a variety of intermediate and final petroleum products in addition 

to crude oil. About 60% of the U.S. petroleum requirements are currently imported, and 

although the U.S. is still one of the world’s largest producers of crude oil, its reserves 

base is only 3% of the world’s proven reserves (British Petroleum, 2005). For the 

foreseeable future, the U.S. will grow increasingly dependent on imported oil for its 

needs. 

 

The raw materials and intermediate materials processed at refineries in the U.S. are 

depicted in Figure A.7. Refinery output is the total amount of petroleum products 

produced (Figure A.8). About 90% of crude oil in the U.S. is converted to fuel products 

that include gasoline, distillate fuel oil (diesel fuel, home heating oil, industrial fuel), jet 

fuels (kerosene and naphtha types), residual fuel oil (bunker fuel, boiler fuel), liquefied 

petroleum gases (propane, ethane, butane), coke, and kerosene (Table A.7). Nonfuel 

products such as asphalt, road oil, lubricants, solvents, waxes and nonfuel coke, and 

petrochemicals and petrochemical feedstocks such as naphtha, ethane, propane, butane, 

ethylene, propylene, butylene, benzene, toluene and xylene, comprise the remaining 

crude conversions. 

 
13

4. OIL AND GAS RESOURCES

4.1. Fossil Fuels 

Fossil fuels consist of plant and animal remains (organic matter) that have been preserved 

in rocks. Organic material accumulated in swamp beds and on the bottom of ancient seas 

hundreds of millions of years ago, and through sediments of sand and mud and conditions 

of high temperature and pressure, a variety of solid, liquid, and gas hydrocarbon 

molecules were created, such as coal, oil, natural gas, tar sands, and oil shale. Since the 

distribution of swamps and ancient seabeds conducive to fossil fuel formation is a 

function of Earth’s plate tectonic and climatic history, fossil fuels are not expected to be 

evenly distributed in the world. 

4.1.1. Coal: Coal is formed from vegetation which grew in swamps hundreds of millions 

of years ago. Peat deposits were built up as vegetation died and accumulated at the 

bottom of swamps to form spongy, brown material, called peat. Geological forces buried 

the peat under the surface of the earth, where the layers were compacted by pressure and 

heat, causing it to release water and other gases in a process referred to as coalification 

(Schobert, 2002). Coal formed from the compressed peat. The greater the heat and 

pressure, the harder the coal; the harder the coal, the less moisture it contains and the 

more efficient it is as fuel. As coalification proceeds, coal increases in rank from lignite, 

to bituminous, and to anthracite, increasing in value, heat content, and quality. Lignite is 

the softest coal and contains the most moisture. Sub-bituminous and bituminous coal are 

medium-soft and medium-hard coal with less moisture and higher heat value. Anthracite 

is the hardest coal with the highest heat content and value per ton mined. 

The most important factors affecting coal quality are ash, sulfur, and trace elements. Ash 

is the residue that remains after burning and consists of clay minerals and quartz. Sulfur 

occurs in various forms and low-sulfur coal is considered to contain less than 1.5% sulfur 

by weight. 

Coal reserves are easy to find and document, and because sedimentary basins are 

widespread throughout the world and the process to form coal is relatively simple, coal is 

the most abundant fossil fuel in the world. Coal beds tend to occur close to the surface of 

the earth, usually within a few hundred feet of the surface. 

4.1.2. Crude Oil and Natural Gas: Crude oil and natural gas are derived from fats and 

other lipids in marine algae and other aquatic plants that were buried with sediment. The 

organic matter transforms into kerogen, an insoluble material that consists of molecules 

much larger than those in oil or gas. With burial, pressure and temperature increases and 

kerogen decomposes to form crude oil and natural gas (Kesler, 1994). 

Crude oils are a complex mixture of hydrocarbon molecules of many different sizes and 

shapes. Each crude oil produced in the world has a unique chemical composition 

containing distillates of different molecular composition, burning qualities, and 

impurities such as metals, asphaltenes, nitrogen, and sulfur (Speight, 1991). The main 
14

characteristics used to classify hydrocarbons include molecular composition, specific 

gravity (density), viscosity, color, and other physical properties. Crude oil is a liquid, and 

because of its chemical composition, is a very compact source of energy that is easily 

transported. 

Natural gas is a mixture of hydrocarbon gases, carbon dioxide, and nitrogen. Methane 

(CH4) is the major constituent, followed by ethane (C2H6), propane (C3H8), butane 

(C4H10), and higher components in smaller fractions. If oil is found in association with 

crude oil, it will have a higher percentage of heavier components which are more 

valuable than methane, not only because they have a higher heat content but because they 

are a valuable refinery feedstock. Gas found in association with coal is referred to as 

coalbed methane. Dry natural gas consists primarily of methane and ethane. 

For an oil or gas field to exist, the geology of the area must have been conducive at some 

point in time to the formation of oil or gas and its storage. Four conditions are generally 

required (Levorsen, 1967): (1) there must be source rocks in which the hydrocarbon was 

generated; (2) this generation process must have reached, but not exceeded, maturity; (3) 

there must be separate subsurface reservoir traps enclosed by impermeable structures that 

prevent oil from escaping and dissipating into the surroundings; and (4) for a 

commercially viable field, the traps must be sufficiently large, either in extent or depth, 

or both, to hold enough hydrocarbon to make the cost of establishing a production facility 

and market delivery system economic. 

Oil and natural gas are formed under significantly more restrictive geologic conditions 

than coal (requiring, “oil windows” and “structural traps” to ensure their creation) in 

deposits that lie thousands of feet beneath the ground over regions that are hostile or 

where access may be limited. Oil and gas reservoirs lie beneath both dry land as well as 

offshore under the oceans. 

 

4.2. Market Value 

The value of crude oil derives from the products which are produced in a refinery. During 

most of the twentieth century, the oil industry has focused on supplying gasoline, the 

highest valued of the refined products of crude oil. The demand for oil has thus come 

mainly from the gasoline (automobile) market, which continues to increase 

incrementally, by a few percent per year as populations and economies grow. Supply, on 

the other hand, tends to increase in discrete amounts in response to periods of high E&P 

activity driven by high prices and as major projects come on-line. 

The market value of crude oil depends primarily on its density and sulfur content. The 

density of oil is related to the relative yields of production that can be extracted during 

the refining process. Sulfur content is important because energy must be spent in refining 

to remove the sulfur to meet product specifications. Heavy, sour crude sells at a 

significant discount to light, sweet crude since it can only be converted in high 

complexity refineries with coking, catalytic cracking, and hydrocracking capacity 

(National Petroleum Council, 2004). 
15

Natural gas is used as a feedstock for petrochemical facilities, by utilities to generate 

electricity, and by residential and commercial establishments for heating. The demand for 

natural gas is seasonal for residential consumers and electric utilities. Industrial and 

commercial demand tends to cycle with the general business environment (U.S. General 

Accounting Office, 2002; U.S. General Accounting Office, 2006). 

4.3. Reserves and Resource Estimates 

Oil and gas resources are classified according to proved, probable, and possible 

categories in the U.S. and proven and possible categories in the U.K. (Gallun et al., 

2001). Companies operating outside the U.S. and U.K., National Oil Companies, and 

private firms employ these and other guidelines in reserves estimation. Reporting 

conventions vary by country, and often do not comply with the strict definitions required 

for company reporting by the U.S. Securities and Exchange Commission (SEC). 

Proved reserves are estimates of the amount of oil or gas (coal, or other resource) which 

can be recovered economically using current technologies. Proved reserves is the most 

certain because it includes only those resources that have already been delineated and 

developed and shown to be economically recoverable using existing technology under 

prevailing market conditions. 

 

Proved reserves have a high probability of eventual recovery, often interpreted as the 

10% fractile of the distribution of recoverable resource; i.e., based on current knowledge 

there is believed to be a 90% chance (P90) of ultimate recovery exceeding this amount. 

Probable and possible reserves are further removed from having been tested by the drill 

bit, and thus, are subject to increasing margins of error. Probable and possible reserves 

are often referred to as P50 and P10, with probable reserves using a longer-term price 

assumption and more advanced technology to estimate underground stores. 

Companies do not normally evaluate project economics based on proven reserves, 

because this is a conservative estimate of resource potential that may not achieve the 

project hurdle rate. Instead, companies apply the less conservative proven and probable 

category, and would prefer that the SEC change its reporting requirements to reflect this 

distinction (LeVine, 2006). Other industry observers (e.g., Simmons, 2005) feel that the 

SEC should make reserves reporting satisfy more stringent conditions than the current 

proved reserves definition. 

The reserves estimates used by the U.S. oil and gas industry are considered fairly reliable, 

since no one is better prepared to understand the geologic conditions and estimate the 

costs of extraction, transportation, etc. than the companies whose business is to make a 

profit and stay in operation. Firms may at times distort or conceal data, but for the most 

part, companies require access to reliable information to make good business decisions, 

and this is reflected in their reserves reporting (Peirce, 2000). 
16

4.4. World Proved and Undiscovered Reserves 

A number of primary and secondary sources report oil and gas reserves and resources. 

Primary sources mostly include company and government data, while secondary sources 

such as World Oil, Oil and Gas Journal, BP Statistical Review of World Energy, Agip 

World Energy Outlook, and Cedigaz compile data from primary sources without review. 

Various commercial data sources are also available that collect and analyze reserve 

estimates on a field-by-field basis. All reserves values are estimates, and so one can 

expect wide variation among the different reported sources. 

 

The United States Geological Survey (USGS) and Minerals Management Service (MMS) 

publish periodic undiscovered resource estimates for the world and U.S. Outer 

Continental Shelf (OCS) based on geologic information, probabilities of past discoveries, 

economic conditions, and various other factors. USGS estimates a probability distribution 

for world resources at the 5% (P5), 50% (P50), and 95% (P95) level. Because of the 

nature of the resource, the uncertainty associated with undiscovered estimates can be 

considered at least an order-of-magnitude higher than the proven or probable reserves 

category. 

The MMS recently completed an appraisal of the technically recoverable oil and gas 

resources for the U.S. OCS. Estimate of undiscovered recoverable resources are 

presented in two categories: undiscovered technically recoverable resources (UTRR) and 

undiscovered economically recoverable resources (UERR). UTRR estimates are 

presented at 95th and 5th percentile levels, as well as the mean estimate (Table A.8). This 

range of estimates corresponds to a 95% probability and a 5% probability of there being 

more than those amounts present, respectively. The 95% and 5% probabilities are 

considered reasonable minimum and maximum values, and the mean is the average or 

expected values (U.S. Department of the Interior, Minerals Management Service, 2006). 

 

Estimates of UTRR for the entire OCS range from 66.6 Bbbl at the F95 fractile to 115.1 

Bbbl at the F5 fractile with a mean of 85.9 Bbbl. Similarly, gas estimates range from 

326.4 to 565.9 Tcf with a mean of 419.9 Tcf. On a barrel of oil-equivalence (BOE) basis 

54% of the potential is located within the Gulf of Mexico. The Alaska OCS ranks second 

with 31 percent. The Pacific is third among the regions in terms of oil potential and 

fourth with respect to gas. 

At the end of 2004, world hydrocarbon reserves amounted to 1.3 trillion barrels of oil, 

6,112 trillion cubic feet of gas, and 1.08 trillion tons of coal (Table A.9). Proven and 

undiscovered oil and gas on a regional (Table A.10) and country basis (Tables A.10-

A.13) indicate geographic distribution. Proven oil reserves are concentrated in the Middle 

East, while gas reserves appear to be more abundant than oil and also more uniformly 

distributed. The largest gas reserves are in Russia, Iran, and Qatar. 

 
17

4.5. Unconventional Resources 

Unconventional resources are an umbrella term for resources that are more challenging to 

extract than conventional resources. Under the right economic and technological 

conditions, however, unconventional resources are expected to add significantly to future 

oil and gas supplies. Today, two “unconventional” oil resources are being produced – 

heavy oil from Venezuela’s Orinoco oil belt and bitumen from Canada’s tar sands. 

Unconventional resources also include oil shale, coal bed methane, gas hydrates, and 

tight gas. Coal bed methane and tight gas are also under active production. Most of the 

world’s known unconventional resources are found in the Western Hemisphere, in the 

U.S., Canada, and South America. 

 

Unconventional resource estimates typically represent the total resource in place and do 

not guarantee economic feasibility, and so reserve estimates are more uncertain than 

conventional resources and should not be compared directly. 

 

4.5.1. Heavy Oil: Heavy oil is oil that will flow under normal reservoir conditions but 

requires Enhanced Oil Recovery (EOR) techniques for economic production. Heavy oil is 

typically easier to locate than light-crude pools and occur closer to the surface, but the oil 

is more difficult and costly to extract, transport, and process. Venezuelan extra-heavy 

crude is nearly as dense as, or denser than, water and significantly more viscous than 

conventional crude. Heavy oil deposits are found throughout the world, but the most 

significant developments are presently confined to Canadian oil sands and the Orinoco 

belt in Venezuela. The USGS estimates that there are 434 billion barrels of technically 

recoverable heavy oil throughout the world (Table A.15). 

 

4.5.2. Tar Sands (Bitumen): Oil that will not flow is referred to as tar (or bitumen). Tar 

can be found in all types of rocks, but tar in sandstones is referred to as tar sands. Tar 

sands are mined and then mixed with hot water or steam to extract the bitumen, and is 

then processed in secondary conversion facilities to convert to a material like oil, called 

syncrude. Most tar stands are currently extracted by strip mining, or by heating or 

solvating underground deposits and pumping out the resulting oil (in-situ production). 

Because the majority of bitumen resources are not surface accessible, in-situ production 

will likely overtake strip mining as operations advance. 

There is no exploration risk in tar sands production, and for that matter, no decline curve, 

but the operation is sensitive to natural gas prices and must have access to sufficient 

water sources. Large deposits of tar sand are found in the Athabasca area of Alberta, and 

Canadian and international oil companies are reported to be prepared to spend $87 billion 

in oil sand development over the next 10 years (Carlisle, 2006). World resource estimates 

for bitumen are shown in Table A.15. 

4.5.3. Oil Shale (Kerogen): Oil shale is shale from which oil can be obtained by 

processing. Shale oil is mined, crushed, and heated to temperature of 500-1,000°C in a 

process called retorting. A large quantity of water, anywhere from 2 to 5 times as large as 

the volume of oil produced, is required in the process. The shale undergoes pyrolsis 
18

which releases hydrocarbon gases and liquids. In the 1980s, $5 billion was invested in the 

U.S. in oil shale projects, but difficult engineering and unexpected economics made all 

the operations commercial failures. Today, oil shales are not currently economically 

recoverable, but high oil prices are again reviving interest in this potential resource. The 

worldwide oil shale resource base is estimated to be 2.6 trillion bbl located across 26 

countries (Johnson et al., 2004a and b). The United States is the world leader in oil shale 

resources with about 2 trillion bbl. The most economically attractive U.S. deposits, 

containing an estimated 1.5 trillion bbl, are found in the Green River Formation in 

Colorado, Utah, and Wyoming. 

 
19

5. OIL AND GAS MARKETS 

5.1. Oil and Gas Are Commodities 

Oil, gas, and the products of refining – gasoline (aviation and motor gasoline and light 

distillates), middle distillates (jet fuel, heating kerosene), fuel oil, and other products 

(refining gas, lubricants, wax, solvents, refinery fuels) – are commodities. Commodities 

are products that are undifferentiated from a competitor and sold on the basis of price, 

defined in competitive markets by the intersection of supply and demand curves at a 

given location and time, and influenced by other factors. Although oil and gas are 

commodities, oil and gas markets have many unique features. 

5.2. Prices Are Determined by Supply, Demand, and Inventory Conditions 

Spot prices are determined by supply, demand, and inventory conditions at a given 

location and time. The most fundamental economic relationship governing commodities 

is that quantity demanded is a function of price. Demand for commodities is generally 

inelastic, and inventories – when they exist in sufficient volumes – allow supply and 

demand to achieve a quasi-equilibrium which acts to smooth out spot prices and reduce 

volatility. Supply is defined by production and inventory, and for energy commodities, 

underground reserves. Balancing supply and demand occurs at both the regional and 

world level. Prices reflect the combined influence of all market information, including 

expectations of future supply and demand, seasonal factors, inventory levels, market 

psychology, etc. 

 

The major upheavals of the world and actions taken by governments over the past 30 

years can be read in the price history of oil (Figure A.9). Events such as the Asian 

financial crises, the 9/11 attacks in the U.S. or the recession of 2001 can all be read from 

historical records. In recent years, global oil demand growth has been high at a time when 

OPEC has little spare oil production capacity. The tight supply/demand balance has been 

exacerbated by market concerns about increased geopolitical supply risk in several oilproducing countries. Oil is a global, fungible commodity, and a change in the supply or 

demand of oil anywhere in the world will affect price everywhere. 

The oil industry has experienced greater periods of growth and restraint than the gas 

industry because historically, oil has been more of an international commodity than gas. 

The price of oil also influence to varying degree the prices of all refined products (Figure 

A.10) and primary fuels (natural gas, liquefied natural gas, coal). 

5.3. Crude Prices Exist in Many Forms 

5.3.1. Benchmarks: The industry has developed a number of reference benchmarks for 

physical and derivative trading (Geman, 2005). West Texas Intermediate, Brent, and 

Dubai are three of the major benchmarks for oil. The price of oil is usually more volatile 

than the differentials caused by the oil quality, and so the prices of other grades of crude 

oil can be compared against the benchmarks and adjusted for quality. 
20

5.3.2. In-Situ vs. Wellhead Prices: The price of a barrel of oil at the wellhead differs 

from the value of a barrel of oil in the ground because the reserve must be produced and 

delivered before being sold to a buyer. Production, depreciation, and transportation 

expenses account for the majority of the price difference. Over the past decade, oil and 

gas reserves have sold on average at about 22% and 36% of their respective wellhead 

prices (Adelman and Watkins, 2003; Smith, 2004). In-situ values are also more stable 

than wellhead prices. 

5.3.3. Spot Prices: Spot prices are wholesale prices for physical delivery at a specific 

transfer point such as a pipeline or at a harbor. Oil spot markets are prevalent worldwide. 

Gas spot markets are only common in countries where the gas industry has been 

deregulated, such as the U.S., U.K., Netherlands, and Norway. 

The price of natural gas is determined on a regional basis, and so it is not possible to refer 

to a “world price” for natural gas. In North America, for example, prices respond to 

demand and supply forces, while in Russia, the state gas company Gazprom holds a 

monopoly position. In Western Europe and Japan, the sales price for natural gas is based 

on competition with alternative fuels and indexed on oil product prices. Most of the gas 

that is traded internationally is in the form of liquefied natural gas (LNG) long-term 

supply contracts to finance the expensive infrastructure. 

5.4. Oil Supply and Demand Imbalance 

The main exporters of crude oil are Saudi Arabia (8.8 Mb/d), Russia (6.7 Mb/d), Norway 

(2.9 Mb/d), Nigeria (2.5 Mb/d), Iran (2.5 Mb/d), and Venezuela (2.4 Mb/d). The main 

consumers are the U.S. (20.5 Mb/d), Western Europe (14.8 Mb/d), China (6.7 Mb/d), and 

Japan (5.5 Mb/d). Geographical imbalances between supply and demand create the need 

for massive exports from the Middle East, the former Soviet Union, and West Africa to 

the Far East, North America, and Western Europe. In Table A.16, production and 

consumption statistics provide a “snapshot” of the imbalance that existed in 2004 

between the net importers and exporters of oil. 

 

5.5. Oil Markets Are Global, Gas Markets Are Regional 

Crude oil markets are fluid, global, and volatile, and have evolved into the most complex 

commodity market in existence today, with an interlocking set of physical and financial 

instruments (Geman, 2005). It costs just a few dollars ($2-3) to transport a barrel of oil 

across the world – a small percentage of the price of a barrel – which explains why oil is 

a global market. If consumption increases in one part of the world or supply disrupted in 

another part of the world, then demand and price signals will transmit the information. 

Consuming nations cannot insulate themselves from the forces driving the world market, 

except perhaps by cutting domestic consumption to the level of domestic production. A 

supply disruption occurs when demand exceeds supply at a specific location and time. 

Supply disruption can never be completely eliminated because there are many factors that 

influence supply adequacy, including growth patterns, crude oil imports, seasonal 

fluctuations, weather patterns, political events, etc. 
21

The cost to transport gas over large distances is significantly more expensive4

 than oil, 

explaining why gas is fragmented into regional markets (Tussing and Tippee, 1995). 

Three regional markets in gas currently exist: United States – Canada, Western Europe – 

(Norway, Russia, Algeria), and Japan – (Indonesia, Australia, Middle East). LNG 

promises to globalize the natural gas industry, but this is still many years away. 

 

5.6. Oil and Gas Prices Are Volatile 

Crude oil and gas prices are more volatile than other commodities, reflecting political and 

economic events, demand, perceptions about resource availability, and many other 

factors (Pirog, 2005a). The volatility of the oil and gas industry usually makes the timing 

of policies ineffective, since the system will change before the policies can take effect 

(U.S. General Accounting Office, 2006). Regions of the world react differently to crude 

price variations, depending on the level of taxation, demand elasticity, government 

support, and many other factors. 

 

5.7. Price Spikes 

Oil and gas prices are heavily influenced by major system discontinuities, such as war, 

regional financial crisis, and political intervention. Because of the balance between oil 

supply and demand, taking even a small amount of oil off the market can cause prices to 

rise dramatically. Geopolitical problems have always affected the oil industry, but these 

problems occurred when surplus capacity could offset disruptions in output from one or 

more regions. 

In late 2002, striking workers in Venezuela, followed by continuing disruptions in 

Nigeria and the U.S.-led invasion of Iraq took several million barrels out of the supply 

mix. So when Iran threatens to cut off supply in their standoff with the U.S. or as Russia 

continues to make foreign investment in their energy sector more difficult, the market has 

a large risk premium embedded in the price of oil. 

There are interesting geopolitical implications associated with the price volatility, since 

rebel groups in Nigeria and countries such as Chad can threaten to disrupt oil supply to 

gain political support or leverage for their cause (Cummins, 2006). 

 

In Oil Shockwave, it was estimated that a 4% global shortfall in daily supply would result 

in a 177% increase in the price of oil (from $58 to $166 per barrel). There have been four 

oil price shocks5

 since the nationalizations in the early 1970s, and the number and 

magnitude of price up-ticks has increased since 1997 (National Petroleum Council, 

2004). 

The economic recessions in the United States are often blamed on oil price increases 

(Hamilton, 1983). Much research has examined the relationship between oil price 

movements and their effects on macroeconomic activity, and although the findings are 

 

4

 On an energy equivalent basis, the cost of gas transportation is about 5-10 times higher than oil. 

5

 A price spike is defined to be a monthly price increase in crude oil in excess of 10% above the prior year. 
22

widely inconsistent, most studies tend to demonstrate measurable relationships between 

oil price shocks and aggregate economic activity. 

 
23

6. DATA SOURCES, DATA QUALITY, AND PROBLEMS OF 

INTERPRETATION 

6.1. Data Sources 

Energy is central to U.S. economic activity and prosperity, and so there is a wealth of 

public data at an exceptional level of detail across all segments of the industry. The 

quality, accuracy, and quantity of the data are superior to any other industry, anywhere in 

the world, but significant analytical difficulties are involved in assessment. The reliability 

and accuracy of data is sometimes difficult to assess, especially when comparing survey 

instruments and data that are unobservable or proprietary. The industry is fragmented 

and complex, and carefully designed studies are required to gain insight into each sector. 

Data requirements vary depending upon the questions to be addressed, the framework 

applied, and the complexity of the phenomena. 

 

A wide range of data sources are available, including government organizations (USGS, 

EIA), international organizations (IEA, OPEC, IFP), private and national oil companies, 

commercial services (IHS, Wood MacKenzie, ODS-Petrodata), and the trade and 

academic press. All sources are useful, and each has their advantages and disadvantages. 

6.2. Data Quality 

 

Data quality varies with the nature of the study under investigation. Field studies which 

require production, quality, and price data are usually easy to assemble and analyze, 

while relevant cost statistics are usually more difficult to gather and collect because of 

proprietary concerns. 

Uncertainty about oil reserves and resources varies throughout the world. In the Middle 

East, reserves data may not change for years, and at other times, fluctuate widely. 

Reserves in OPEC countries are often considered exaggerated because of cartel polices 

and are often criticized for being either under- or over-reported. For example, several 

OPEC countries significantly increased their estimates of proved reserves in the late 

1980s even though little exploration or appraisal drilling took place at the time 

(Simmons, 2005). Estimates remain opaque because of a lack of credible external 

auditing of national claims. 

 

The manner in which public companies report their expenditures, reserves, and account 

for cost is highly variable. In the U.S., two accounting methods are generally practiced – 

successful efforts and full cost accounting – with majors and large independents tending 

to favor successful effort methods, and smaller independents favoring full cost methods 

(Gallun et al., 2001). Outside the U.S. accounting practices diverge widely. 

A number of investment banks, government agencies, consultancies, and trade 

publications survey the oil and gas industry to gauge their E&P budget plans and to 

assess their view of the industry. The coverage of the surveys varies with the 

organization, and the results are generally not directly comparable across instruments, 
24

firms or time due to the nature of the data collection. Spending surveys and cash flow are 

difficult to assemble on a county-by-country basis, and are usually only available on a 

regional or global level with a high level of noise due to the survey methodology (survey 

vs. public records), coverage (sample size), instrument specifications (aggregation, 

categorization, etc.), and other factors. 

 

Public records can be used to review a company portfolio of assets and the manner in 

which capital is allocated across business sectors as a function of time. Public 

information does not include the risk-reward profile of projects, however, corporate risk 

profiles, or risk-adjusted6

 discount rates. 

 

6.3. Problems of Interpretation 

The oil and gas industry is far too complex and dynamic for simple cause and effect 

relationships to be developed. The most useful perspective is often a description of what 

has actually happened, rather than the development of complex theory, which due to 

tractability issues, simplifying assumptions of behavior or system discontinuities, will 

often leave the analysis unrealistic (Stevens, 2001 and 2002). Descriptions of what has 

actually happened, however, are often subject to the experience, qualifications, and bias 

of the analyst, and may provide little or no insight into the structure or drivers of a 

particular issue. It is for this reason that a balance must be achieved between empirical 

models and mere descriptions of events. Analysts rely upon aggregated and observable 

data to draw inferences and make conclusions, but the process of aggregation and the link 

between data and behavior is often tenuous or ambiguous to render a model useful. 

 

6.3.1. Microeconomic vs. Macroeconomic Perspective: The microeconomic model of 

behavior which governs an individual firm does not easily generalize to macroeconomic 

models which relate to the aggregate (regional, global) industry. Some descriptor 

variables may overlap, but for the most part, the factors will vary significantly. World 

E&P capital spending, for example, is composed of the expenditures of all industry 

participants – majors, independents, and NOCs – throughout the world. NOC data is 

unobservable. Aggregate expenditures vary across time and are likely to be at least 

partially explained by demand and price variables, as well as factors such as spare 

capacity and non-OPEC production. These same factors, however, are not likely to be 

useful to predict firm behavior, which would use cash flow, profitability (return on 

capital), strategic opportunity, or expected future outlook to guide business investment. 

The issue to be examined thus dictates the categories employed and the factors selected in 

model construction. 

6.3.2. Aggregation: Data may be aggregated in a number of ways, due to the source of 

the data or the preferences of the analyst. Aggregation is a useful way to deal with 

uncertainties or the impact of variables that cannot be modeled, but the process of 

aggregation necessarily destroys the information content of the data. In capital 

 

6

 Companies tend to focus on technical or country risk assessments to risk-adjust cash flows or discount 

rates in project evaluation. The assessments are conducted by different corporate divisions or by external 

advisors; e.g., (Aven, 2004; Wood, 2003). 
25

expenditure surveys, for example, segments of the business are typically presented 

according to upstream and downstream sectors and decomposed along a company, 

country, region, or world basis. If any one sector (e.g., exploration and production) is 

analyzed in isolation from other business activities, the system will probably be 

misspecified. Oil and gas streams are frequently combined in terms of a BOE-basis, 

which will introduce additional uncertainty, since oil and gas streams are not identical on 

a heat-equivalent basis and have been valued quite differently over time. Aggregation 

generally “smoothes out” uncertainties, but the process may lead to misspecification or 

bias, or both (Lynch, 2002). Finding costs and reserve replacement ratios, for instance, 

are particularly poor metrics when computed on an aggregate basis. 

6.3.3. Omitted Variables: System behavior and trends are explained through 

measurable/observable factors, which imply a correlative relationship and predictive 

ability, but relations may be spurious due to omitted variables. The factors that affect 

demand and supply, capital investment and country competitiveness are determined by 

economic principles and commonly accepted industry notions, but there is no general 

analytic framework that can accommodate all the potential interacting factors. Individuals 

will likely disagree on specific factors, their specification, relative importance, level of 

aggregation, and causality. Since there are so many potential factors, it is unlikely that a 

factor set will suffice in explaining all aspects observed. 

 

6.3.4. Factor Types: Factors may be observable or unobservable, deterministic or 

stochastic, one- or n-dimensional, time varying, cyclic, or fixed. Economic fundamentals 

or intuition may suggest a possible direction for each factor under consideration, when 

other factors are held constant (or equal), but unfortunately, “other factors” are rarely 

equal and the interaction of effects may be beyond modeling capability. Factors may 

create pressures in one direction for one period of time, the opposite direction for another 

period of time, and remain ambiguous over a third time horizon. Relationships that are 

derived based upon a given set of structural assumptions are usually not valid during 

periods of high factor volatility or when the system structure changes. System structure is 

itself an artificial construct of our imagination and thus a subjective and ambiguous 

concept. 
27

7. FACTORS THAT IMPACT SUPPLY AND DEMAND

The supply of oil in the world at any point in time is the sum of the production levels 

achieved by the collection of many private, public, and state-owned companies. Each 

individual producer plans for and decides on its own supply level independently, with the 

exception of OPEC members, and possibly, short-term “alliances” that may form during 

exceptional times; e.g., extreme price levels, military activity, etc. For the members of 

OPEC, the level of supply results from the coordination and collective decisions of the 

member nations. The goals, strategies, and behavior of private and public companies vary 

widely, but investment decisions for companies tend to be based on profitability criteria, 

the companies’ cash flow position, and its outlook for the future. International oil 

companies have shareholders who require a return on their investment. The goals, 

strategies, and behavior of state-owned companies on the other hand are much more 

diverse. National oil companies have domestic social and political obligations, the need 

to create foreign exchange, and the desire to exert geopolitical influence. 

 

The demand for oil and gas begins at the individual and corporate level. Individuals drive 

cars; heat and cool their homes, and consume food and other services, all of which 

require – either directly or indirectly – oil, gas, and petroleum products. Corporations 

provide goods and services which also require energy. Aggregating the individual, 

commercial, and industrial demands of a nation comprise the demand function for the 

country. 

 

7.1. Economic Activity 

Energy availability and consumption play a key role in the process of economic growth, 

and conversely, is an essential input into technological advancement in the substitution of 

machines and other forms of capital for human labor. Energy use is a necessary input to 

economic growth and is also a function of growth. 

Energy use is associated with population growth, the expansion of urban centers, 

industrialization, and the development of infrastructure such as roads and transportation 

networks (Chima, 2005). It takes energy to produce things of value, and thus, there is 

typically a strong correlation between a country’s energy consumption and economic 

activity as measured by gross domestic product7

 (GDP). The nature of the relationship is 

dynamic and will change over time with technological progress and the demand 

requirements of the industrial, commercial, and residential segments of the nation (Mory, 

1993). 

 

In the U.S., economic growth is linked to high levels of oil, natural gas, and electricity 

consumption, but a feedback mechanism provided by the market generally limits the 

impact. As GDP growth rates and demand increase, price will also tend to increase, 

which may lead to more restrictive monetary policies and/or a consumer reaction, both of 

 

7

 The GDP is a measure of the total market value, expressed in dollars, of all final goods and services 

produced within a nation in one year. 
28

which will potentially slow the rate of GDP growth and limit energy consumption (Pirog, 

2005a). In China, these same forces are at play as expanding exports increase the 

industrial demand for oil, and rising consumer income has increased consumers’ demand 

for gasoline. For countries whose oil exporting sector is a major component of their GDP 

(e.g., Russia, Nigeria, Saudi Arabia), the expansion of the oil sector is itself likely to lead 

the growth in GDP8

. 

7.2. Inventory

The expectation that oil and refined product inventories influence prices is based on the 

assumption that prices reflect the current supply/demand balance, and that inventories 

provide a measure (albeit imperfect) of the changing balance between supply and demand 

(National Petroleum Council, 2004). Any factor that serves as a measure of the shortterm supply/demand balance would be expected to influence prices, but the impact will 

vary depending on the market perception of the importance of the factor, how fast the 

information flows to the market, and other conditions at the time of observation. An NPC 

study found only a modest correlation between inventory levels and crude oil price 

(National Petroleum Council, 2004). The U.S. Department of Energy (DOE) found a 

slightly stronger relationship when total crude and product inventories, recent inventory 

trends (lag terms), and relative inventories measured by actual inventories versus 

“normal” inventories defined by seasonal trends were included (Ye et al., 2003). A 

relationship between inventories and the shape of the forward price curve exists, with 

inventories positively correlated with the forward price spread. 

7.3. Price 

Price is by far the most accessible and reliable data series available, and thus, is a 

preferred explanatory variable for supply and demand forecasting. Crude oil price is 

determined in the world market and depends mainly on the balance between world 

demand and supply. Markets respond to supply/demand changes with price movements 

that provide the incentive to increase or decrease supply to correct imbalances (Adelman, 

1993; Seba, 2000). High prices lead to increases in exploration and development budgets, 

and as new oil and gas is found and brought to the market, supply increases and prices are 

typically reduced. High prices can also make alternative fuels more competitive, 

potentially reducing demand, and are likely to encourage conservation, further reducing 

demand. 

 

7.4. Geopolitics 

Geopolitical shifts and foreign policies play an important role in global energy security 

and long-term energy supplies. The fall of communism and the liberalization of 

 

8

 For countries where oil and gas comprise a large part of total export revenue, economic downturns are 

more likely when oil markets shift. It has been observed that countries with significant oil reserves often 

end up with low growth rates because they are less willing to adopt restructuring and can afford to shun 

foreign investment and basic economic criteria in decision making (International Monetary Fund, 2004; 

Karl, 1997). 
29

economies in Asia and South America have opened vast energy resources previously 

inaccessible or underdeveloped, while China and India’s growing concern about the 

rising cost of energy and their dependence on import oil has prompted their state-owned 

companies to aggressively seek acreage and investment opportunity throughout the 

world, often through aggressive bidding and in regions with high political risk. China’s 

demand for steady supplies of oil is reshaping the global energy market, the environment, 

and world politics (Obaid et al., 2002; Wonacott et al., 2003; U.S. Congressional Budget 

Office, 2006). India is next in line, as its government will try to achieve a better lifestyle 

for its population. 

Market reforms in a country will usually improve production and encourage foreign 

investment, while nationalism will typically lead to reduced investment, at least in the 

short term (Kennett and Goswami, 2006). A growing number of countries across South 

America, for example, are opting for more nationalist, left-leaning governments (e.g., 

Bolivia, Ecuador, Venezuela) as opposed to the market-oriented policies of previous 

moderate, socialist governments. Throughout Africa, South America, and the Former 

Soviet Union, governments and their NOCs are renegotiating contracts to take in more 

revenue via taxes and royalties (Coburn, 2005). In the 1990s, Russia divested itself of 

some off its biggest industrial assets in often-controversial privatizations. Since 2002, the 

Kremlin has sought to regain control of the energy sectors. State-owned energy 

companies OAO Gazprom and OAO Rosneft, for example, have purchased independent 

oil producers, OAO Sibneft and OAO Yukos. Iran continues to feud with the West over 

its nuclear ambitions, and continued conflict in Nigeria maintains a risk premium in the 

price of oil. 

 

Geopolitical events can create pressures in either direction, with both short and long-term 

consequences, and it is easy to overstate their influence and underestimate their effect. 

Geopolitical events by their nature are impossible to predict (Mitchell, 1996; Mitchell et 

al., 2001). 

7.5. Geology 

The geology of a country or province will ultimately determine the energy supply 

potential of the region. There is a finite amount of oil and gas resources in the world, but 

whether we ever extract all of the resource or find other alternative sources is a matter of 

heated debate (Campbell, 1997; Lynch, 2003; Maugeri, 2004; Reynolds, 2005; Watkin, 

1992). At present, there is no good substitute for oil or gas, and so as long as demand 

outstrips supply, prices will remain at elevated levels. 

 

7.6. Access to Reserves 

Resources in the ground are the property of the state, except in a few countries around the 

world such as the United States and parts of Eastern Canada where private ownership of 

minerals is legal (Barrows, 1983). Countries maintain sovereign rights over the land and 

mineral resources within their physical territory, and in the case of access to water (lake, 

sea, and ocean), offshore continental shelf acreage. Opportunity to explore for and 
30

develop oil reserves depend on host country policies on foreign investment, depletion 

rates, and environmental protection. By the mid-1990s, many countries had at least 

partially opened their oil sector to foreign investment, but three major oil-producing 

countries still remain totally closed – Kuwait, Mexico, and Saudi Arabia. Investment in 

Russia, China, Iraq, and Iran remain constrained by regulatory, political, and 

administrative barriers and delays (International Energy Agency, 2003). 

7.7. Technology 

Technological advances in the oil and gas industry have been phenomena over the past 

two decades. Vastly increased computing power has stimulated the development and 

interpretation of geophysical data, which has led to a better understanding of reservoir 

characteristics. Progress in 3-D and 4-D seismic techniques, advances in deepwater 

exploration, horizontal drilling, multiphase pumps, floating production storage and 

offloading vessels, have all made a contribution to increasing supply. It is widely 

recognized that technological advances have improved drilling productivity and recovery 

rates and reduced production costs, especially offshore and in frontier areas, but its 

impact is difficult to isolate. Technological advances raise the proportion of a field which 

can be economically recovered, while improvements in infrastructure allow smaller 

and/or deeper fields and less productive wells to be economically produced. Improving 

technology will continue to make more reserves available. 

 

7.8. Exchange Rates 

 

World oil is priced in dollars and transactions are settled in dollars, and so changes in the 

exchange rate of the U.S. dollar can affect the level and distribution of oil demand in both 

directions. The effect of a declining dollar depends on the import/export status of the 

nation and how the currency of the country adjusts to the changing value. If the value of 

the dollar declines against other currencies, the dollars received by oil exporting nations 

are worth less in purchasing power, which may impact their production decisions. For oil 

importing nations, the impact depends on the trade-off between the advantages of an 

appreciating currency and product exports (Pirog, 2005a). 

7.9. Depletion (Existing Fields) 

As a field is produced, its productive capacity declines if no investments (additional 

drilling, enhanced recovery schemes, etc.) are made. With no additional investment, a 

field will typically decline at a rate ranging between 5-20%. Investment will slow the 

decline of the field, depending on the geology of the field, and the nature of the 

investment. The majority of investment in the oil industry is currently spent to 

compensate declining production rates. The International Energy Agency (IEA) estimates 

that about 20% of investment is required to meet new demand growth, with the remaining 

80% used to compensate for decline (International Energy Agency, 2003). 
31

7.10. Discovery Rate (New Fields) 

High oil and gas prices stimulate drilling activity, which usually results in increased 

production, but the geology and maturity of the region in which drilling occurs are 

constraining factors. Geology determines what resources are ultimately available, while 

technical and exogenous factors – including infrastructure, field complexity, proximity to 

market, oil price – determine if the field is commercial. If the region is mature and 

infrastructure well developed, field discoveries will be small on average but can be 

brought on-line with relative ease, while if the region is frontier, the chance of a large 

discovery is greater but the development cost will be more. 

 

7.11. OPEC Policy 

OPEC was organized in 1960 by Saudi Arabia, Iran, Venezuela, Iraq, and Kuwait in 

protest of the multinationals move to reduce posted prices for exporting countries. Today, 

there are 10 member nations, excluding Iraq. The stated objective of OPEC is to 

“... co-ordinate and unify petroleum policies among Member Countries, in 

order to secure fair and stable prices for petroleum producers; an efficient, 

economic, and regular supply of petroleum to consuming nations; and a 

fair return on capital to those investing in the industry.” 

 

OPEC seeks to create favorable oil prices for its members by assigning production quotas 

to its member nations (Table A.17) with the goal of limiting the supply of crude oil 

available on the world market. The behavior of OPEC and its institutional structure is the 

subject of intense academic and government interest, and many conflicting viewpoints 

have been espoused about the nature of OPEC, its success in maintaining a price band for 

crude, its incentives for increasing supply, and its expected role in the future. 

OPEC supply can be considered a planned and managed variable, resulting from the 

coordination and collective decisions of the member nations. The level of supply is 

frequently adjusted, sometimes several times a year, in response to anticipated 

developments in market fundamentals, where factors and expectations of factors such as 

the price, demand, stock, and non-OPEC supply are used to make adjustments (Smith, 

2005). 

 

OPEC’s stated policy is to reduce the market volatility and to stabilize the oil price within 

a suitable price band. OPEC countries are not uniform in their behavior, however, and 

each has different policies to maximize income (e.g., quota cheating) and openness to 

foreign investment. 

7.12. Role of National Oil Companies 

The behavior and strategies of NOCs and their investment and trade patterns are 

important to oil supply because they control the vast majority of proven reserves in the 

world. Saudi Arabia alone controls nearly 25% of the world’s proved oil reserves. Iran 
32

(11%), Iraq (10%), Kuwait (8%), UAE (8%), and Russia (6%) also control significant 

quantities of proved reserves and have mostly limited foreign investment in the sector. 

National Oil Companies are expected to have a substantial, long-term, and growing 

impact on the pace of resource development, market stability, and geopolitics. 

There is a wide diversity in the structure of NOCs. Prior to 1960, most NOCs formed 

around specific local issues and the desire for self-sufficiency, while during the 1970s, 

many countries nationalized their assets to regain control from foreign companies and 

achieve higher rents from production. In the 1980s, after oil was commoditized and price 

volatility and falling prices negatively impacted profitability, oil ministries and NOCs 

began to restructure to increase their efficiency and return on capital standards were 

increasingly employed. In the 1990s and post-2000, countries with economies in 

transition reorganized their oil ministries to form NOCs and private firms (Jaffe, 2005; 

National Oil Company Case Study Research Protocol, 2005). 

Economic liberalization, market reforms, and western-style management reorganizations 

have characterized the oil and gas industries of major energy producing countries such as 

Russia, Norway, Canada, and Malaysia, as well as major consuming countries such as 

China, Brazil, Japan, and India. National Oil Companies are in the process of reevaluating and changing business strategies with significant consequences for 

international majors and market stability. 

7.13. Exceptional Events 

War, riots, political instability, natural disaster, and terrorism impact the supply and 

demand for oil and gas. Exceptional events by definition are unique and impossible to 

predict. The impact of exceptional events on oil and gas markets has potential short-term 

and long-term consequences, depending on the state of the world oil market at the time of 

the event. Some notable examples of exceptional events from 2001-2005 include: 

• War in Iraq, 

• Terrorist attacks in New York, Saudi Arabia, and elsewhere, 

• Political unrest and riots in Nigeria, Venezuela, 

• Nationalism in Bolivia, Ecuador, Venezuela, Russia, 

• Hurricanes Katrina and Rita along the Gulf Coast, and 

• Legal conflict between Yukos and the Russian government. 

According to Department of Energy statistics, the Iraqi invasion and aftermath rank as the 

third-largest cumulative oil disruption since World War II, behind the nationalization of 

Iran’s oil fields in the early 1950s and the Iranian revolution in 1979 (Table A.18). 

Weather-related disruptions will impact production in the short run, but are not expected 

to have significant consequences in the long-term. Terrorist activity and political unrest 

can negatively impact air travel and other sources of demand, and directly impact supply 

reliability. 
33

Discontinuities impact the ability to forecast supply and demand trends over time (Lynch, 

2002; Stevens, 2000 and 2001). When discontinuities occur, the future will be 

fundamentally different and historic trends significantly disrupted. System discontinuities 

are therefore frequently ignored in analytic models, but such impacts are integral to the 

nature of the system. The further into the future a forecast is made, the larger and more 

frequent potential discontinuities will arise. 

 

7.14. Market Manipulation 

 

The primary markets in oil price formation are NYMEX and the International Petroleum 

Exchange. The goal of financial traders is to make a profit on changes in the price of a 

contract, which necessitates creating price movement, regardless of the supply-demand 

fundamentals of the market. Market manipulation may impact price formation and the 

signals governing the supply-demand balance. 

7.15. Government Policy 

Government policy takes many forms and can have a direct impact on supply and 

demand and investment patterns. Each nation in the world has a variety of regulations 

which affect investment in the oil and gas sector, including tax structure, price controls, 

import/export controls, access to prospective territories, fiscal policies governing E&P 

activity, etc. Each nation also has geopolitical aims which affect investment trends, 

partnerships, strategies alliances, and regional cooperation. Policy variables are 

notoriously difficult to model and are subject to a number of competing political 

processes. 

7.15.1. Licensing and Incentives: Governments control investment in the oil and gas 

sector primarily through their policies on foreign investment, the number of tracts leased, 

and the frequency of license rounds. The opening of a country or region, or the expansion 

of license acreage, may shift investment to the region, depending on the perception of the 

industry and the state and stability of the oil markets at the time. Governments may also 

provide incentives for operators, such as through royalty relief and other mechanisms, to 

promote exploration activities in high cost-high risk areas, and during times of low oil 

price. The openness of countries to foreign direct investment is an important factor in 

determining how much investment occurs in the country. 

7.15.2. Taxation: Hydrocarbon taxation strategies are variable and dynamic, depending 

on government interest, the global economic environment, and on the income the country 

wishes to derive from hydrocarbon production. Each country is a special case. Every year 

is a specific event. Tax rates vary by country and over time, and often, on a field-by-field, 

company-by-company basis, negotiated as part of the fiscal system. Taxation systems 

evolve rapidly in response to market conditions and the margin that the state wishes to 

allocate to the oil companies. 

 

Producing/exporting countries try to derive the maximum possible income from their 

hydrocarbons, while industrialized/importing countries generally attempt to encourage 
34

domestic production by stable fiscal regimes and tax incentives. Producing exporting 

countries will try to secure the maximum amount of revenue through taxation. Major 

consuming/importing countries will adjust their legal and tax systems to encourage E&P 

activity on their territory to improve their balance of payments and to protect the 

industry. 

 

7.15.3. Fiscal Regime: The fiscal terms offered by host governments are a critical 

determinant of the attractiveness of an upstream investment. All governments have to 

balance their desire to maximize their share of rent versus the need to encourage 

investment. This is a matter of judgment since the attractiveness of a region depends on 

perceptions of geological, economic, and political risks relative to projected returns. The 

stability of a fiscal regime is important, since frequent changes or changes applied 

retroactively will force investors to raise their hurdle rates, which may limit future 

investment. 

The E&P market is characterized by sometimes sudden changes in an area as a 

consequence of the changes in the power relationships between the producing states and 

the international companies. The period following the second oil crisis witnessed the 

growing power of the producers/exporters and a tightening of the terms of E&P contracts. 

Oil companies, eager to sign new contracts and anticipating further oil price increases, 

found themselves in a weak negotiating position. The trend reversed in the mid-1980s as 

oil prices plunged and E&P activity in producing countries was curtailed. Countries 

reviewed their legal framework and introduced more flexibility into their contracts. The 

decade of the 1990s witnessed increasing government control over the activities of oil 

and companies. It is likely that the industry will continue to shift between these extremes. 

 

7.15.4. Environmental Regulations: Environmental considerations and public 

opposition to oil and gas projects affect opportunities for investment and the cost of 

projects. In the U.S., moratoriums on drilling in federal onshore lands and offshore 

coastal zones have been in place for many years, which obviously impact the potential 

supply of domestic oil and natural gas. 

7.15.5. Conservation: 

Conservation policies of a country and tax rates on petroleum products are an important 

factor affecting the demand for crude oil. 

 

7.16. Political Risk 

Whenever oil and gas capital flows overseas, political risk is a real and ever-present 

danger. In the 1950s, companies were mostly concerned with nationalization, while 

today, the risk is for the terms of the contract to be re-written to such as degree that 

operations are no longer economic. The widespread use of production sharing agreements 

has largely removed the nationalization risk, since the oil now belongs to the host county, 

but political risk remains a significant factor in many parts of the world as contract terms 

are renegotiated (McArthur et al., 2000). 

 
35

8. FACTORS THAT IMPACT E&P INVESTMENT 

 

In the E&P industry, many factors influence drilling and development decisions and the 

manner in which a company allocates capital across its portfolio. A firm should seek to 

maximize profits, but financial forces and shareholders (banks, fund managers, etc.) may 

require a firm to pursue “growth” (reserves volume) or diversify its operations. At a 

corporate level, the decision to allocate resources in any given year depends upon its cash 

flow position, the profitability of the business, preferences for risk taking, competition in 

the global marketplace for capital, available prospects for drilling, strategic decisions, 

shareholders obligations, and the firms outlook for the future. At the time a company sets 

its budget, it should be able to make a fairly reliable projection of next years production 

rate and estimated cost. Typically, a planning horizon for oil prices is assumed and 

projects are evaluated on a common and consistent basis, where judgments on the risks 

and rewards of the projects under a variety of price scenarios and geologic, technical, 

production, government, tax, and legal factors are considered (Seba, 2000). 

8.1. Financial Performance 

 

Investment decisions are made within a firm based on the amount of money a company 

has to invest, which depends on commodity prices, cash flow, profit margins, and 

expected profit. High commodity prices tend to lead to higher profit, and vice versa, but 

since costs and taxes also change with price, the correlation is not perfect. Profit can only 

be determined on a project-by-project basis taking into account the terms of the fiscal 

regime, royalties, taxes, production costs, and other relevant factors. 

 

Cash flow is the primary source where companies acquire funding for new projects. The 

price of crude and derivative products are major determinants of cash flow, but like 

profit, available cash flow is also influenced by several other factors, including dividend 

reinvestment, share buybacks, and debt reduction. Cash flow tends to follow movements 

in prices and production. Companies react to reduced cash flow by cutting upstream 

investments and shifting the available capital to projects in other regions of the world 

with a better risk-return profile. If suitable projects are not available elsewhere, the 

company will hold a cash inventory. 

The firms that make up the oil and gas industry in the U.S. use shareholder (public) or 

private capital to engage in business operations. When firms make profits they are 

obliged to return those profits to shareholders, either directly in the form of dividends or 

indirectly through share repurchases. In a market economy, decisions on the use of profit 

are the responsibility of the industry in which they are earned. 

 

8.1.1. Dividend Strategy: Dividend policy varies widely with each company, based on 

factors such as company size, corporate outlook, and cost of capital (Brealey and Myers, 

1991). Majors tend to act conservatively based on long-term planning horizons. 

Shareholders of the majors expect a larger portion of their return to be derived from 

dividends than smaller companies, and thus will normally tolerate a lower level of 

production growth. 
36

8.1.2. Share Purchases: A company that re-purchases its shares will likely see the value 

of the shares outstanding increase. The company may then choose to re-sell their shares 

on the market if it needs capital in the future. 

8.1.3. Debt Reduction: Banking institutions are an important source of funds to the oil 

and gas industry, but generally cost more than other forms of financing. Most companies 

rely on banking for short term borrowings such as a line of credit, revolving credit 

agreement, transaction loan, or dedicated cash operating income payment. 

 

8.2. Availability of Capital 

If the capital employed in a company does not generate an adequate return, the company 

will have limited access to new capital, as investors and lenders seek more profitable 

opportunities elsewhere. The availability of capital is not expected to be a constraint to 

investment for integrated oil and gas companies in the short-term, however, because of 

the return on investment (ROI) for the sector over the period 1993-2002 has been high for 

publicly traded companies in the Organization for Economic Cooperation and 

Development (OECD) and non-OECD regions (Figure A.12). Integrated companies 

realized the highest return (12%) across various industries, while the ROI of independent 

companies in E&P was 6.3%, the lowest for all industry sectors. 

8.3. Budget Allocation 

Oil and gas companies will expand and upgrade various aspects of their operations, such 

as refining, petrochemicals, marketing, and transportation, at various times depending on 

the strategic rationale of the company. Companies may also diversify into other industries 

such as mining or non-energy related activities. The degree of vertical integration affects 

the degree to which capital is allocated across the various segments of the business. 

8.4. Business Opportunities 

Investment in the oil and gas sectors may be constrained by a lack of profitable business 

opportunities. Upstream investment decisions depend on company’s assumptions 

regarding future oil price, planning horizons, hurdle rates, etc. (Chua and Woodward, 

1992; Turner, 1983). Oil companies that favor a conservative price assumption, perhaps 

reflecting pressure from shareholders to maintain high investment returns, are likely to 

have a decline in capital spending. 

 

8.5. Oil Price 

The price of hydrocarbons is probably the single most important factor in the E&P 

industry, because for companies that produce oil and gas, price and income are closely 

related: lower prices reduce income, high prices increase income. The correlation is not 

perfect, of course, but the relationship is strong enough to suggest that the price of oil is 

likely to be a reasonably good explanatory variable for E&P investment in markets such 

as the Gulf of Mexico, Canada, and the North Sea. In other parts of the world, however, 
37

the correlation between price and capital expenditures is likely to be weaker and more 

closely dependent upon the nature of the field developments, project size, time lags, 

planning horizon, and other unobservable variables. High prices tend to lead to increases 

in company exploration and development budgets, and if the current market follows past 

patterns, increased activity and expansion of supply. 

 

Price enters the drilling decision through the calculation of the potential payoff associated 

with a play. High prices stimulate drilling decisions, because the economic and reward 

structure appear more favorable. When prices drop, companies are inclined to curtail 

some of their exploration activity, and if prices stay low long enough, companies will 

shut-in high-cost wells, delay development activity, and postpone high risk ventures. At 

low commodity prices, M&A activity is usually more prevalent, with majors selling 

properties and shifting their budgets to regions/activities with a greater return. Strong 

prices will tend to delay divestiture programs, since properties that are marginal at low 

prices become profitable. In recent years, as demand-side NOCs have begun to secure 

reserves for their host country through high-cost acquisitions, these relations may change. 

 

8.6. Oil Price Volatility 

Oil and gas investment has tended to fluctuate with oil prices, especially in recent years, 

but the relation is not a universal phenomenon and several other factors are involved. A 

careful examination of the historic record indicates that capital spending in E&P may 

increase or decrease when the price of oil increases. A price collapse will typically lead to 

a reduction in investment spending, although the magnitude will vary depending on 

several other (unobservable) variables. High prices tend to encourage investment 

spending, but the life cycle of exploration and development means there is a several year 

delay. Price uncertainty will raise the option value of future investments and firms are 

likely to postpone or reduce expenditures on irreversible investments. IEA analysis has 

found support for an inverse relationship between upstream oil investment and price 

volatility (International Energy Agency, 2003). 

 

8.7. Merger and Acquisition Activity 

 

If a company is under merger, acquisition, or reorganization this will typically slow down 

or delay capital spending. Corporate mergers in which one company acquires another 

companies total assets impact exploration and development decisions. M&A activity may 

improve the market position of the firms involved, but they do not change the oil supply 

balance of the world. M&A activities are likely to help majors compete internationally to 

acquire acreage and develop joint partnerships with NOCs in the future. 

8.8. Debt/Equity Position 

 

Companies with a significant amount of debt will have fewer funds available for 

reinvestment. Restructuring by cost reduction and asset divestiture will lead to reduced 

spending in the short term, and possibly longer term future returns. 
38

8.9. Business Uncertainty 

Investment decisions in capital intensive and high risk industries such as E&P tend to be 

based on full-cycle project economics, expected long-term prices (Boudreaux et al., 1999; 

Wehrung, 1989), portfolio decision-making (Edwards and Hewett, 1995; Hightower and 

David, 1991), and strategic rationale (Seba, 2000). Capital requirements in E&P compete 

with other segments in the petroleum industry as well as the capital needs of other 

industries. Uncertainty about the future price of oil and gas and global conditions impacts 

allocation decisions and external evaluations by bond raters and capital markets (Pirog, 

2005b). 

 

The higher profitability of integrated oil and gas companies relative to independents and 

service companies (recall Figure A.11) reflects the nature and diversity of their assets and 

operations. The volatility of ROI by industry is depicted in Figure A.12. Exploration and 

development and service companies have a volatile ROI, while the volatility of integrated 

companies is comparable to the chemical industry. For decisions that require a large 

amount of capital, increased uncertainty tends to slow down or stop investment in order 

to reduce risk. Uncertainty over regulations and license rounds would also be expected to 

lead to reduced capital investments. 

 

8.10. Capacity Constraints 

The E&P industry is composed of many diverse companies and resource constraints 

which are likely to vary widely among individual companies and regions of the world.

E&P projects are designed and engineered by a combination of internal company 

resources and third-party companies, ranging in size from small engineering firms to 

multi-billion dollar companies. The support equipment and services required (e.g., rigs, 

vessels, personnel, materials) to successfully execute an E&P project is driven by supply 

and demand forces at a particular place and time, and has not historically been a 

significant constraint to project implementation. There is evidence to indicate that 

reduced capital spending by oil-services companies, which result in less availability of 

oilfield equipment, has at times forced oil and gas companies to scale back their 

investment programs (International Energy Agency, 2003), but the impact is usually 

short-term because an increase in demand will increase dayrates9

, which will stimulate 

new investment, increasing supply and competition, and balancing the market. 

 

8.11. Resource Availability 

Oil and gas companies create value by investing in those projects for which the market 

value of cash inflows exceeds the required investment outlays. The purpose of drilling is 

to discover reserves, but it costs money to identify plays, acquire and interpret seismic 

data, and drill wells. If the resources found are not adequate to make a sufficient return on 

capital, then the E&P industry in the region will drop and shift investment where the 

return is acceptable. If the region is not prospective, or if the NOC controls the best 

 

9

 For example, if rig rates remain high for a sustained period of time, then cold-stacked rigs will come back 

into service and new-build orders will occur, increasing rig supply and forcing down rates. 
39

blocks, then foreign capital will eventually diminish and move to other regions or 

business opportunities. 

8.12. Risk Strategies 

Investing in energy projects in developing countries and the transition economies is 

generally riskier than in OECD countries because of institutional and organizational 

reasons; lack of clear and transparent energy, legal, and regulatory frameworks; and 

poorer economic and political management. There is also a significant difference in the 

risk and return profile between an export project and a project for the domestic market in 

non-OECD regions. Risk strategies and the means to manage risk vary with each 

company. 

 

8.13. Government Policy 

Governments choose their production capacity potential based on a number of factors. 

OPEC producers, for example, may determine that curbing investment and limiting 

capacity would boost net earnings from exports. OPEC producers also recognize the risk 

that other producers (OPEC or non-OPEC) might boost their capacity more quickly, 

resulting in lower export earnings for the country. Governments might defer investment 

to preserve hydrocarbon resources and revenues for future generations (Reynolds, 2005). 

This could be a legitimate policy for a country with relatively high GDP per capital and 

no pressing need for additional oil revenue to fund infrastructure or social programs. If 

governments increase taxes and royalties on production, or otherwise change the terms 

and conditions of the fiscal regime, lower profitability of upstream projects might deter 

investment. 

 

8.14. Exogenous Variables 

Numerous external factors also play a role in the amount of capital a country can invest in 

its oil and gas sector (International Energy Agency, 2003): 

• If a country’s national debt is high and there is a need to borrow large sums to 

finance new projects, investment may be delayed. 

• National sovereignty might discourage reliance on foreign investment. 

• Legal and commercial terms and fiscal regimes impact how much external 

capital producers are able to secure. 

• In many countries, education, health, defense, and other sectors of the 

economy may command an increasing share of government revenues and 

constrain capital flow to the oil sector. 

• Inadequate infrastructure to support oil and gas development, insecurity, and 

conflict could constitute additional barriers to investment. 
41

9. E&P EXPENDITURE TRENDS

Exploration and production activity cannot be explained solely on the basis of geology. 

Politics, economics, technology, regional and global markets all act to preclude, foster, or 

inhibit E&P activity and capital investment. E&P activity varies with a country’s demand 

for crude oil and natural gas within its border, as well as the desire to export oil and gas 

as a means of gaining foreign exchange. When the oil industry is in a state of “over 

supply-low prices,” companies are more reluctant to invest capital to seek/acquire new 

exploration sites; when the industry is in a state of “under supply-high prices,” companies 

more aggressively seek out exploration opportunities. Increasingly, oil and gas companies 

will be competing with NOCs to secure exploration acreage, and although there is yet to 

be significant partnering between the two parties, the survival of oil and gas companies 

rely on access to resources, and so movement in this direction may be inevitable. 

 

9.1. U.S. Major Energy Producers 

One of the best sources of public data on the financial and operating developments in the 

U.S. petroleum sector is the EIA’s Performance Profiles of Major Energy Producers. 

The EIA collects financial and operating data through a Financial Reporting System 

(FRS) Form EIA-28 from a sample of major U.S. energy companies that are considered 

representative of the U.S. energy industry. A “major energy producing” company must 

satisfy at least one of the following criteria to be included within the survey: (1) control at 

least 1% of U.S. crude oil or natural gas liquids reserves or production, (2) 1% of U.S. 

natural gas reserves or production, or (3) 1% of U.S. crude oil distillation capacity or 

product sales. 

 

Information is collected for the corporate entity as well as by lines of business within the 

company; e.g., petroleum, downstream natural gas, electric power, non-energy, and other 

energy. The petroleum line of business is segmented into exploration and production, 

refining and marketing, crude and petroleum product pipelines (for domestic petroleum), 

and international marine transport (for foreign petroleum). 

 

The FRS data are separated by regions which include U.S. onshore, U.S. offshore, 

Canada, OECD Europe, former Soviet Union and Eastern Europe, Africa, Middle East, 

other Eastern Hemisphere (primarily Asia Pacific), and other Western Hemisphere 

(primarily South America). 

 

The composition of the FRS group of companies changes over time, but since the 

changes are usually incremental, year-to-year comparisons of the survey data are 

considered meaningful. In 2004, 29 major energy companies reported data, representing 

operating revenues of $1.13 trillion, equal to about 15 percent of the $7.4 trillion in 

revenues of the Fortune 500 corporations (U.S. Energy Information Administration, 

2004). About 94 percent of operating revenues of the companies were derived from 

petroleum operations. The FRS companies accounted for 46% of total U.S. crude oil and 

natural gas liquids (NGL) production, 43% of natural gas production, and 84% of U.S. 

refining capacity. 
42

9.1.1. Return on Equity: The return on stockholders equity for the FRS companies 

varies considerably from year-to-year and has fluctuated with the S&P Industrials (Figure 

A.13). Oil and natural gas production was the most profitable segment of the business 

($59 billion), followed by refining/marketing ($22 billion), and non-energy activities ($4 

billion). 

The return on net investment is defined as the net income earned by the line of business 

(excluding unallocated items such as interest expense) as a percentage of net fixed assets. 

The return on net investment for domestic oil and natural gas production operations has 

exceeded foreign operations in recent years (Figure A.14), whereas prior to 1995, the 

returns from foreign operations dominated. 

9.1.2. Sources and Uses of Cash: The sources and uses of cash for FRS companies are 

shown in Table A.19. Cash flow from operations amounted to $136 billion in 2004, with 

oil and natural gas production comprising 65% of the total. At significantly smaller 

levels, cash was also raised through disposal of assets, long-term debt, and equity security 

offerings. 

Cash flow is a primary determinant of the level of capital investment, ranging anywhere 

between 15-40% of net income in a given year (Beck, 2004). In 2004, the largest use of 

cash was for capital expenditures, which increased 8% to $86.5 billion (Table A.19). 

Petroleum activities accounted for 86% of capital expenditures. Dividends to 

shareholders were the second largest use of cash, followed by reduction in long-term debt 

and stock repurchase. 

 

9.1.3. Capital Expenditures: Capital expenditures for exploration10, development, and 

production generally follow changes in cash flow, except most recently in 2004, where a 

wide differential resulted (Figure A.15). A positive change in oil price is usually 

associated with a less moderate but positive change in cash flow, while a negative change 

in oil price is often correlated with a zero or negative change in cash flow. In Figure 

A.16, worldwide expenditures are broken out according to exploration, development, and 

production activities. 

Regionally, the U.S. onshore continues to receive more E&P expenditures than any other 

region, followed by the U.S. offshore (Table A.20). Exploration expenditures for the U.S. 

offshore are almost twice onshore expenditures (Figure A.17), while expenditures for 

development continue to predominate in the U.S. onshore (Figure A.18). The U.S. 

continues to attract a disproportionate share of FRS capital investment because oil is 

found at the market place, can be developed with low cost infrastructure, and can be 

brought on-line in a short period of time. The political risk in the U.S. is small, or 

negligible, and the potential for commercial discovery is still considered strong. 

 

10 Exploration costs include all the investment that is needed before a discovery is confirmed, including 

geophysical and geological analysis and drilling exploration wells. Development costs cover spending after 

a discovery is confirmed and delineated. Development costs include the installation of surface equipment 

and facilities and drilling production wells. Production costs represent the costs to operate and maintain 

wells and related equipment after hydrocarbons have been found, acquired, and developed. 
43

Foreign exploration and development expenditures have not changed significantly over 

the past several years. Limited access to prospects in the Middle East and South America 

has restrained E&P expenditures in these regions, while Africa and Canada remain the 

favored destination for FRS companies. FSU countries continue to exhibit significant 

growth in development expenditures. 

9.2. U.S. Independent Producers 

The perceptions of U.S. independents are surveyed in a variety of sources. The American 

Oil & Gas Reporter’s annual survey of independent operators’ list factors that operators 

consider inhibits drilling and production activity (Campbell, 2005). In 2005, concerns 

about price volatility lead the list, cited by 69% of the respondents as a reason why the 

industry is not drilling at a more robust pace, followed by equipment/personnel 

availability (58%), higher equipment and service costs (53%), environmental regulations 

(36%), smaller reserve targets (34%), insufficient prospect inventories (34%), and 

acquisition opportunities (26%). Small and mid-size operators primary concern is price 

volatility, while for large operators, the availability of equipment and personnel is 

considered the limiting factor. 

 

In a Grant Thornton survey, executives and chief operating officers from 75 independents 

representing total average assets at the end of 2005 of $836 million and average revenues 

of $167 million were questioned. Executives responded that area restrictions, good 

projects, service costs, availability of equipment, and the aging work force were the 

primary factors expected to limit capital spending in the upcoming year. 

Survey results are notoriously difficult to generalize and compare, and in almost all cases, 

the information simply confirms generally accepted industry perceptions. It is reasonable 

to suspect that the perceptions of executives and other decision makers would translate 

into concrete, verifiable behavior, although in practice the link is tenuous and difficult to 

verify. It is also difficult to build models of industry behavior based on survey data 

because of the variability of the results and its limited application. In some years, 

independents may spend more domestically and majors may be most interested in 

unconventional plays; in other years the reverse may be true. In some years, independents 

may be more interested in exploration activities and demonstrate greater sensitivity to 

price changes; in other years the reverse may be true. Surveys usually cannot provide 

adequate information from which to generalize. Indeed, one must be exceedingly careful 

when attempting to interpret and/or explain any “patterns” or “trends” in the industry 

with behavior and/or macroeconomic models. 

9.3. Capital Expenditures 

9.3.1. Data Source: Lehman Brothers performs a semiannual E&P spending survey 

based on a poll of international firms, including privately held U.S. and Canadian 

independents and several National Oil Companies. Smith Barney, Chase/Saloman 

Brothers, John S. Herold, Harrison Lovegrove & Co., Citigroup Investment Research, 

Grant Thornton, Prudential Equity Group, Inc., Raymond James & Associates, Arthur 
44

Anderson (now Accenture), and other financial institutions perform similar surveys. 

Government agencies that perform capital expenditure reviews and outlooks include the 

Energy Information Administration (EIA), International Energy Association (IEA), and 

Institute of Petroleum (IFP). Consultancies such as IHS, Ziff Energy, Wood MacKenzie, 

Douglass-Westwood, and trade publications such as The Oil and Gas Journal, American 

Oil and Gas Reporter (O&GJ), and World Oil, also conduct annual capital spending 

surveys. 

 

The surveys typically cover issues such as: 

• Expected spending plans for the upcoming year, by region (U.S., Canada, 

international), activity (upstream, downstream, business segment), and 

company type (majors, independents, NOCs); 

• Perceptions on expected changes in service and drilling costs, merger and 

acquisition activity, oil and gas price assumptions, availability of prospects, 

availabilities of drilling services, impact of technology on spending plans, 

remaining reserves expected to be found, human resource issues, 

compensation for technical staff; and 

• Perceptions on the relative attractiveness of investment opportunities 

(exploration vs. development, U.S. vs. international, drilling vs. acquisition 

activity, oil vs. gas plays), expected operating cash flows, spending plans 

(leasing, seismic, onshore vs. offshore). 

 

Significant variations in the manner in which data is compiled and processed make it 

difficult to compare survey results. In Table A.21, for example, global upstream oil and 

gas investments for four surveys are compared from 1995-2002. Wide variation exists, 

suggesting that a composite average is probably the most representative statistic, avoiding 

the uncertainty and bias associated with any single data series. Creating a composite 

average of this sort, however, based on divergent survey data is methodologically 

problematic. 

 

9.3.2. U.S. and Non-U.S. Capital Spending: In the O&GJ survey, U.S. capital spending 

is decomposed according to three upstream categories: drilling-exploration, production, 

OCS lease bonus; and eight downstream categories: refining, petrochemicals, marketing, 

crude and products pipelines, natural gas pipelines, other transportation, mining, and 

miscellaneous (Table A.22). 

Capital expenditures by U.S. firms for U.S. upstream and downstream sectors generally 

follow the U.S. majors spending profiles. Investment in the U.S. has been volatile over 

the past two decades, generally tracking the price of oil, the amount of capital flowing 

into the industry (cash flow), and the level of profitability. 

 

9.3.3. Worldwide Capital Spending: Global capital expenditures represent the sum of 

all public, private, and state-owned companies in the oil and gas industry (Table A.23). 

Spending plans for oil and gas companies outside North America, South America, and 
45

Europe, are either mostly unavailable (Middle East, Africa) or available in incomplete 

form (Asia Pacific). Worldwide investment in E&P has tended to follow the price of oil, 

especially in the years prior to 1998, but the correlation is noisy and dependent upon the 

data series employed. When the price rises or falls, exploration budgets adjust quickly to 

the changes, while development budgets tend to be delayed. Some regions of the world 

react faster to price variations than others, with North America generally considered to be 

the most price-sensitive. 

After the nationalizations in the 1960s and 1970s, the majors needed to redeploy capital 

throughout the world to access acreage. Exploration and production budgets matched the 

price shocks of 1973 and 1979 as demand growth increased. From 1981-1987, prices 

suffered as excess supply developed from the previous investment boom. Capital 

expenditures were reduced and prices retreated. From 1987-1998, prices stabilized below 

$25/bbl and a more cautious approach to investment was realized. Following the price 

collapse in 1998, capital expenditures took a temporary fall before continuing on an 

upward slope. 

 

9.4. IEA Investment Forecast 

The IEA predicts that an investment of over $3 trillion, or $103 billion per year, will be 

needed in the oil sector through 2030 to permit an increase in oil supply to 120 million 

BPD by 2030 (International Energy Agency, 2003). Exploration and development is 

expected to dominate the investment, accounting for over 70% of the total. Investment in 

non-conventional oil projects in Canada and Venezuela is expected to account for a 

growing share of total upstream spending. Offshore fields are expected to account for 

about a third of the increase in production from 2002 to 2030, but will take a larger share 

of investment, because the unit costs are higher compared to other developments. 

9.5. Lifting Costs 

Lifting (production) costs represents the costs to operate and maintain wells and related 

equipment and facilities after hydrocarbons have been found, acquired, and developed. 

Lifting cost is a reliable and meaningful measure, and can be compared across companies 

if a common accounting framework is applied. Lifting cost is a measure that may be used 

to evaluate the extent to which a company can control its operating costs and/or how 

efficiently the company is getting oil and gas out of the ground. Two mechanisms are 

responsible for boosting productivity and reducing lifting costs: technical progress and 

industry reorganization. 

Total lifting costs are divided into direct costs and production taxes. Direct costs tend to 

be correlated to the price of oil since increases in oil price tend to bring an increase in the 

cost of service and supply costs. Production taxes may also be a function of the price of 

oil and other factors, especially under Production Sharing Agreements. 

 

For the FRS companies, Canada and the Western Hemisphere region have the lowest 

direct lifting costs in the world, while the Former Soviet Union and Eastern Europe have 
46

the highest direct lifting cost (Table A.24). This is likely due to a combination of political 

systems, technical progress, and industry organization. Direct cost in the U.S. offshore 

lies between these extremes. Domestic and foreign direct lifting costs are nearly identical 

and have trended together for the past decade (Figure A.19). 

9.6. Finding Costs 

Finding costs is one of the most frequently cited ratios utilized in evaluating the 

efficiency of a company in adding new reserves. Finding costs is also one the most 

misapplied and ambiguous measures in the industry (Adelman, 1993; Gaddis et al., 

1992). Finding and development costs can be defined in many ways, and there is no 

general consensus on the best way to define the measure, leading to significant 

limitations in measurement and interpretation. In the FRS Form EIA-28, finding costs is 

defined as the costs of adding proven reserves of oil and gas through exploration and 

development on a BOE-basis, including the purchase of properties that might contain 

reserves. A 3-year weighted average is reported in 2004 constant dollars (Table A.25). 

Finding costs have been rising since the mid-1990s and have been the most variable for 

the U.S. offshore region (Figure A.20). 

 
47

10. IMPLICATIONS OF EXPECTATIONS ABOUT FACTORS 

AFFECTING CAPITAL BUDGETING AND DECISION MAKING 

FOR THE OCS GULF OF MEXICO

Keeping in mind the caveats and qualifications outlined in the previous sections of the 

report, the following tables attempt to use the format developed to relate “conventional 

expectations” concerning those factors to future investment trends in the OCS Gulf of 

Mexico. The “conventional expectation” is a subjective characterization by the authors of 

the perceptions, opinions, and analyses prevailing among those that follow the oil and gas 

industry. Our characterization, as well as the perceptions, opinions, and analyses we 

offer, may be neither complete nor accurate. We may also err in drawing our 

characterizations. In any event, the reader can form his own thoughts in the matter. 

Alternative characterizations can be substituted and alternative implications derived at the 

reader’s discretion. The tables are simply a way to relate the implications of the complex 

and interrelated factors outlined in the previous sections of the report for the Gulf of 

Mexico region. 
48

Table 1 

Factors that Impact Supply and Demand 

FACTOR 

/REPORT 

SECTION 

CONVENTIONAL 

EXPECTATION 

IMPLICATIONS FOR 

INVESTMENT IN THE 

OCS GULF OF MEXICO 

 

7.1 

Economic 

Activity 

Rapid growth in most populous 

developing countries, resumption of 

growth in Japan and Europe, and 

average or above growth in the U.S. 

will keep global petroleum demand 

increasing faster than in the 

previous two decades. Although 

global or regional recessions could 

always slow or stop growth, the 

impetus for growth seems 

widespread and resilient to political 

and cultural disputes and conflict. 

Growth in demand is the factor 

responsible for the expectation of 

continued higher oil and gas prices, 

which is an important driving force 

for investment in relatively high 

cost areas like the GOM. 

 

7.3 Price 

Demand growth will continue to 

strain available supply capacity and 

prices are likely to stay at current 

high levels or increase. 

High prices are the key to the 

economic vitality of GOM 

investments. The expectation of 

their continuation makes investment 

in domestic oil and gas production 

competitive with other domestic 

investment opportunities for the 

largest private companies. 

 

7.4 

Geopolitics 

Continued instability, uncertainty 

and realignment in oil-exporting 

countries in the Persian Gulf, 

Russia, FSU, South America and 

Africa. 

Political and institutional stability in 

the U.S., Canada, and Europe, 

compared to deterioration and 

increased risk elsewhere, increases 

the relative expected value, and 

attractiveness, of GOM 

investments. 

7.5 

Geology 

Significant prospects are more 

likely to be found outside the GOM, 

but uncertainty about the realism of 

Saudi Arabian reserve estimates 

will continue to be a major concern. 

Uncertainty about Saudi Arabian 

reserve estimates is a contributing 

factor to expectations that higher 

prices will endure. 
49

Table 1 (continued) 

Factors that Impact Supply and Demand 

FACTOR 

/REPORT 

SECTION 

CONVENTIONAL 

EXPECTATION 

IMPLICATIONS FOR 

INVESTMENT IN THE 

OCS GULF OF MEXICO 

7.6 Access 

to Reserves 

Incremental erosion of existing 

moratoria on exploration and 

development of U.S. reserves, but 

most such areas will remain offlimits. Geopolitical concerns and 

conflicts and difficulty in working 

with NOCs limit effective access to 

reserves in many major producing 

areas in the rest of the world. 

Expansion of access to the Eastern 

GOM creates new investment 

opportunities in a stable 

environment with well developed 

infrastructure, supporting services, 

and accessible markets. 

7.7 

Technology 

Somewhat more emphasis on 

technologies to improve recovery 

from mature and unconventional 

fields. 

Any progress on recovery 

technologies from mature fields 

will help GOM investment 

prospects. 

7.9 

Depletion 

More GOM production will come 

from maturing fields, less from new 

discoveries. 

Eighty percent of investment is 

currently spent to slow declining 

production, and so there is a modest 

impetus for increased investment as 

fields mature in areas such as the 

GOM. 

7.10 

Discovery 

Rates 

Frontier regions with potential 

large discoveries need more 

investment in infrastructure. 

As a mature region with extensive 

infrastructure, less investment is 

required to develop and produce 

new discoveries which make 

production of smaller fields and 

higher cost fields more feasible. 

7.11 OPEC 

Policy 

Prices are well above the upper 

bound of OPEC’s desired price 

range, but OPEC has only limited 

ability or incentive to increase 

production for economic reasons. 

Expansion of capacity is not a task 

that OPEC tries to manage. The 

circumstances and motivation of 

individual OPEC members varies. 

Less risk of price decline than 

when Saudi Arabia had the ability 

to increase production from 

mothballed capacity quickly and 

substantially--as was routinely 

assumed during the 1980s and 

1990s. A substantial amount of 

existing, potential supply capacity 

is “offline” or not producing in 

Iraq, Nigeria, and Venezuela for a 

variety of reasons, but how quickly 

production could return is 

questionable. “Too much” capacity 

being added in Persian Gulf is the 
50

Table 1 (continued) 

Factors that Impact Supply and Demand 

FACTOR 

/REPORT 

SECTION 

CONVENTIONAL 

EXPECTATION 

IMPLICATIONS FOR 

INVESTMENT IN THE 

OCS GULF OF MEXICO 

7.11 OPEC 

Policy 

(Cont.) 

 principal, long-term downside 

supply risk to prices. 

7.12 Role of 

National Oil 

Companies

National Oil Companies (NOCs) 

are more subject to geopolitical 

considerations and less driven by 

conventional commercial 

objectives. Coupled with the 

Russian retrenchment and 

aggressiveness by the Chinese, 

risks of large investments in 

exporting or in transitional 

economies may have increased. 

Relative investment attractiveness 

of GOM is increased. 

7.13 

Exceptional 

Events 

Political instability and uncertainty 

appears to be spreading rather than 

moderating. 

Vulnerability of deep water 

operations to major hurricanes and 

new regulatory requirements to 

deal with them are the principal 

new uncertainties associated with 

GOM investment. 

7.15 

Government 

Policy 

Political instability in Persian Gulf 

and Africa, nationalism in South 

America, economic retrenchment in 

Russia, and the uncertain path of 

evolution of the FSU countries 

reduce the certainty and reliability 

of current government policies and 

institutions. 

 

The royalty relief controversy and 

the potential for the resurrection of 

some form of excess profit taxation 

are potential direct uncertainties in 

the GOM, but neither is of the scale 

of those in many exporting 

countries. Climate policy and 

carbon taxes are longer range 

uncertainties. Shorter-term 

uncertainty exists in the GOM 

about new regulations to address 

problems observed during Katrina 

and Rita. 
51

Table 2 

Factors that Impact E&P Investment 

FACTOR 

/REPORT 

SECTION 

CONVENTIONAL 

EXPECTATION 

IMPLICATIONS FOR 

INVESTMENT IN THE 

OCS GULF OF MEXICO 

8.1 Financial 

Performance 

Mega-majors and large integrated 

companies can maintain high profit 

levels if they have access to 

reserves. In 2004, the FRS 

companies’ net income of $81.1 

Billion was the highest (in constant 

dollars) in the history of the FRS 

series. Smaller independents have 

not been as profitable as the large 

firms in the high price 

environment. 

The FRS companies are major 

players in the GOM and constraints 

and uncertainties elsewhere 

enhance the attractiveness of GOM 

E&P investments for them. 

Independents have historically 

been a growing presence in the 

GOM and opportunities to invest in 

other areas are more limited. 

8.2 

Availability 

of Capital 

High profit levels for large 

integrated firms will enable them to 

generate or compete for capital 

effectively. Smaller, less profitable 

independents may have more 

difficulty. 

The historically anomalous excess 

of cash flow from operations over 

E&P expenditures (Figure A.15) 

indicates an increased availability 

of internal capital for FRS 

companies. As expectations about 

the continuation of a high-price 

environment harden with time, 

access to capital by independents 

also may increase. 

8.3 Capital 

Budget 

Allocation 

Experience of investing in, or 

merging with, non-oil and gas 

businesses in the 1980s and 1990s 

was not good. Some companies are 

making exploratory or “learning” 

investments in alternative energy 

ventures, but for most majors and 

independents, the core business 

will remain oil and gas. 

Competition between U.S. onshore 

and offshore has been going in the 

direction of onshore, with 2004 

total onshore U.S. E&P twice the 

1998 level while the 2004 offshore 

was at roughly the same level as 

1998. Exploration expenditures on 

the offshore remain about 50 

percent higher than onshore. 

Diversions to other businesses or 

increased intra-company 

competition for investment dollars 

are not anticipated to change. The 

payoff from GOM investments (as 

well as onshore U.S. investments) 

has been good. U.S. investments 

should be more attractive relative 

to other alternatives in capital 

budgeting deliberations. The 

principal new negative that may 

influence capital budgeting 

decisions is the demonstrated 

vulnerability of GOM 

infrastructure to hurricanes. 
52

Table 2 (continued) 

Factors that Impact E&P Investment 

FACTOR 

/REPORT 

SECTION 

CONVENTIONAL 

EXPECTATION 

IMPLICATIONS FOR 

INVESTMENT IN THE 

OCS GULF OF MEXICO 

8.3 Capital 

Budget 

Allocation 

(Cont.) 

Refining has to some degree been 

spun off to specialized refining 

companies and neither they nor the 

traditional integrated companies 

exhibit much enthusiasm for 

investing in new refineries. 

8.4 Business 

Opportunities 

Limitations on access to domestic 

reserves and increased risks 

associated with NOCs and 

transitional economies are as 

likely to intensify as moderate. 

Some FRS companies will seek 

non-oil and gas business 

opportunities, but their business 

culture has not transferred well in 

the past. Oil and gas will remain 

their core business and nonUS/Canada oil and gas 

opportunities have become riskier. 

Stockholders may push for more 

aggressive, non-oil and gas 

investments if dividends fall 

because earnings are invested in 

financial assets. 

8.5 Oil Price 

Expectations that prices will 

remain at or above current levels is 

a major change in the fundamental 

investment parameter for investorowned oil and gas companies. 

There is considerable variation in 

estimates of how capital budgets 

will reflect this change in 

economic fundamentals, but 

standard project decision practices 

will make many marginal projects 

now profitable. 

With current prices twice or three 

times as high as they were when 

projects were implemented, GOM 

profits are correspondingly higher 

than anticipated. 

8.6 Oil Price 

Volatility 

Demand-driven, much-higher, 

prices imply a much smaller risk 

of a precipitous decline in prices 

than has been assumed in the 

previous two decades. 

Expectations that price volatility 

has diminished shifts the relative 

balance of risks away from 

economic and cost factors and 

toward the geopolitical, noneconomic side. As a higher cost 

but politically and institutionally 

stable area, the attractiveness of 
53

Table 2 (continued) 

Factors that Impact E&P Investment 

FACTOR 

/REPORT 

SECTION 

CONVENTIONAL 

EXPECTATION 

IMPLICATIONS FOR 

INVESTMENT IN THE 

OCS GULF OF MEXICO 

8.6 Oil Price 

Volatility 

(Cont.) 

 the GOM is enhanced by this shift. 

8.7. Merger 

and 

Acquisition 

Activity 

The major industry consolidation 

and corporate restructuring among 

the majors during the past decade 

was driven by the need to be large 

enough to compete internationally 

and deal with NOCs effectively. 

Although size may address 

commercial risks it is not as 

effective in mitigating geopolitical 

risks which have been increasing 

rapidly. Post-merger adjustments, 

and their accompanying 

conservatism with respect to 

capital spending, have been 

completed by the mega-majors. 

Mergers and acquisitions among 

independents remains active as has 

historically been the norm. 

More FRS companies are large 

enough to accommodate the 

progressively larger investments 

required to develop large projects 

in deeper water in the GOM. 

8.8 

Debt/Equity 

Position 

Debt-to-equity ratios of the FRS 

companies fell to 45 percent in 

2004 which is below the average 

for Standard and Poors (S&P) 

Industrial Companies. 

Coupled with substantially 

increased holding of Treasury bills 

and cash, this reinforces the 

expectation that oil and gas 

companies will have more capital 

available than has historically been 

the case as long as prices stay high. 

According to surveys of 

independents expectations, neither 

debt nor capital availability were 

among the factors they expected to 

limit capital spending. 

Reinforces expectation that capital 

will be available for GOM 

projects. 
54

Table 2 (continued) 

Factors that Impact E&P Investment 

FACTOR 

/REPORT 

SECTION 

CONVENTIONAL 

EXPECTATION 

IMPLICATIONS FOR 

INVESTMENT IN THE 

OCS GULF OF MEXICO 

8.9 Business 

Uncertainty 

Hardening expectations about the 

durability of a high-price, reducedvolatility environment represents a 

major reduction in economic 

uncertainty in a capital intensive 

industry such as oil and gas E&P. 

The degree to which this offsets 

the heightened geopolitical 

uncertainties is an open question. 

Oil companies have historically 

operated in politically unstable 

countries even in times of 

considerable crisis. 

8.10 

Capacity 

Constraints 

Availability of drilling rigs and 

experienced personnel are widely 

cited as barriers to exploration and 

development by FRS companies as 

well as independents. Similar 

constraints would also retard 

development of supporting 

transportation and processing 

infrastructure in pioneer areas. 

Historically the capital intensive 

E&P industry has overcome these 

barriers fairly expeditiously once 

investment decisions are made. 

Day rates for drilling equipment 

are two to three times higher than 

they were five years ago and 

effective utilization rates of 

drilling equipment is 100 percent, 

but service companies are 

investing in new equipment 

aggressively. To the extent that 

capacity constraints postpone 

investment activity, however, they

will have more depressing effects 

in pioneer areas as opposed to 

mature areas with a well developed 

transportation and processing 

infrastructure and easy access to 

markets--such as the GOM. 
55

Table 2 (continued) 

Factors that Impact E&P Investment 

FACTOR 

/REPORT 

SECTION 

CONVENTIONAL 

EXPECTATION 

IMPLICATIONS FOR 

INVESTMENT IN THE 

OCS GULF OF MEXICO 

8.11. 

Resource 

Availability 

U.S. moratoria and explicit 

limitation by NOCs or 

governments limit investment 

opportunities. There are some 

indications of a weakening of the 

moratoria coalition in the U.S. 

because of state-level budget 

needs, but major changes are not 

expected in non-U.S. areas in the 

current high-price environment. 

Aspirations for economic 

improvement in developing and 

transitional economies remain 

strong and create pressure to find 

and develop resources. 

Resource limitations make access 

to resources in the GOM relatively 

more attractive. 

8.12. Risk 

Strategies 

Risks in non-OECD countries are 

higher for political and 

institutional reasons. There are few 

indications are that this disparity 

will diminish and many expect it to 

widen because of geopolitical and 

nationalistic trends and influences. 

U.S. political and institutional 

stability is a major advantage of 

GOM investments. 

8.13. 

Government 

Policy 

Major uncertainties and risks will 

remain in the non-OECD 

countries—especially in the 

Persian Gulf, South America, 

Africa and the transition 

economies. 

Although regulatory policy, access 

to publicly owned reserves, 

royalty-relief, and similar issues 

remain, in a global perspective, 

governmental policy is of much 

less concern in the GOM than 

elsewhere. 
56

The global circumstances confronting those making capital budgeting and investment 

decisions for oil and gas companies have changed in important ways during the past five 

or six years. 

• Economic factors, in general, have improved substantially. Prices, in constant 

dollars, are very near historic highs for oil and have surpassed those highs for gas-

-when expressed in constant dollars. Economic growth is strong-to-stable 

everywhere except Africa and global demand growth has substantially exceeded 

expectations. Excess production and refining capacity has for all practical 

purposes been eliminated. Normal adjustments to higher prices will slow demand 

growth, encourage new supplies and the development of alternative fuels and 

technologies; however, factors that would precipitate a collapse in prices to levels 

enjoyed during the 1980s and 1990s are not apparent. 

• For non-economic factors, in general, the changes are as pervasive and important, 

but unfortunately negative rather than positive. Geopolitical considerations, 

nationalistic aspirations, cultural/religious conflict and their derivative 

complications have increased the risks and uncertainties associated with 

petroleum investments in many regions of the world where reserves are believed, 

or hoped, to be most plentiful. Risks of making petroleum investments in those 

regions have increased significantly. Historically, however, oil and gas companies 

have managed to operate confidently and effectively in politically unstable and 

hostile countries even in times of considerable crisis. 

Policies to mitigate or manage non-economic risks are dominated by other, and more 

fundamental, objectives than creating a stable environment for investments in petroleum 

development. There are divergent opinions about such policies prospects for success. 

However, as long as the improved economic factors remain as they are, and the 

deterioration of non-economic factors is not reversed, the implication is that the 

attractiveness of investing in mature areas, with existing support infrastructure, located in 

stable and predictable political and institutional environments, such as the OCS GOM, 

has increased relative to other opportunities—both opportunities to invest in more 

commercially rewarding but less politically secure areas, or to invest outside of oil and 

gas. 
57

11. COUNTRY COMPETITIVENESS 

The oil and gas industry is far too complex and dynamic for simple cause and effect 

relationships to be developed to explain the nature of a country’s fiscal regime. The 

structure of fiscal regimes depend upon many interdependent non-causal factors such as 

the reserve base and economic strength of the country, oil supply balance, oil prices, 

evolution of political systems and historic relationship between the industry and the 

country, field maturity and development stage, regional demand, the country’s desire for 

foreign capital, geopolitical motivations, and many other variables. Countries with low 

exploration risk and high prospectivity are generally expected to take a high proportion of 

economic rent, while countries with high exploration risk and low prospectivity must 

usually offer a larger share of rent to encourage investment. 

 

11.1. International Petroleum Arrangements 

The economics of the upstream petroleum business is complex and dynamic. Each year 

anywhere between 25-50 countries in the world offer license rounds, 20-30 countries 

introduce new model contracts or regulations, and nearly all countries revisit their tax 

laws during their annual budgetary process. Typical (or “average”) country or regional 

contracts do not exist, and the terms and conditions of most contracts are proprietary, and 

at best, partially observable. 

There are more fiscal systems in the world than there are countries because 

• Numerous vintages of contracts may be in force at any one time, 

• Countries typically use more than one arrangement in license rounds, and 

• Contract terms are often negotiated and renegotiated as political and economic 

conditions change, or as the perception of prospectivity in a region change. 

The information used to analyze fiscal regimes is often incomplete and uncertain because 

• Terms and conditions of contracts are considered proprietary, 

• Field specific information is often not available, and 

• Changes in the external environment are tied to fiscal terms in various ways. 

As a country’s domestic production declines or flattens, the oil and gas companies within 

the country will look at foreign exploration opportunities to expand operations and 

increase growth potential. Companies compete to obtain licenses to explore and develop 

reserves from countries that compete to attract foreign investment and technology. 

Competition exists between companies, countries, and regions to attract foreign 

investment. As profits fall or rise in one geographic region or play, companies shift their 

funds and/or revise their business models and strategic objectives to capture the best rate 

of return consistent with their risk-reward strategy. 
58

11.2. Contract Types 

In order to convert mineral assets into financial resources, a government must attract 

investment capital to explore for, develop, and produce its natural resources. Many styles 

of contracts govern the arrangements between Host Government (HG) and International 

Oil Company (IOC) engaged in E&P activity. These arrangements have evolved over 

many decades in response to political, economic, technical, and geologic conditions. 

Today, there are essentially four basic types of E&P contracts: 

• Concessionary (Royalty/Tax), 

• Contractual (Production Sharing Contracts), 

• Participation Agreements, and 

• Service Agreements. 

Each arrangement provides for different levels of control to the IOC, for different 

compensation arrangements, and for different levels of NOC involvement. Many 

contracts share elements from one or more categories. 

Royalty/Tax systems allow the title to hydrocarbons to transfer to the IOC, while under a 

contractual system, the HG retains title to the mineral resources and maintains closer 

control of the management of the operation. Participation agreements create a joint 

venture between the HG and IOC through the NOC as partner. In a service agreement, a 

company agrees to perform a service for a monetary payment. Service agreements rarely 

include a right to share in production, and outside Mexico and the Middle East, are not 

popular for E&P activity. Royalty/Tax and Production Sharing Contracts (PSC) are the 

most common agreements in use today. 

 

11.3. Exploration Market 

The market for exploration acreage is competitive, finite, and nonhomogenous. 

Governments offer exploration acreage through formal competitive bidding rounds or 

through individual negotiation. The market for acreage follows supply and demand 

fundamentals with demand expected to follow the price of oil and the cash flow position 

of industry. The supply of acreage has increased over the past two decades as countries 

outside the Middle East have opened up new areas for exploration, especially on their 

continental shelves. The amount of acreage available for E&P is also finite and 

determined through national jurisdiction. The quality of acreage is not homogeneous, 

however, and different regions have different “prospectivity,” depending upon geologic, 

fiscal, legal, and political factors. 
59

11.4. Capital Market 

Governments compete for E&P capital in much the same way that companies compete to 

acquire exploration acreage. Governments compete on a regional and (to some extent) 

international basis with other countries to attract capital, while companies compete on a 

regional and international basis with other companies, and increasingly, NOCs to acquire 

acreage. Investment capital flows to regions under the influence of complex economic, 

historic, political, and strategic factors governed by perceptions of risk and return and 

constrained by the objectives of the contractor and the prospectivity of the country. When 

countries compete, the share of economic rent may become depressed, while when 

companies compete, profit margins are likely to be impacted. Countries may offer 

favorable terms to companies to compensate for other factors, such as an unattractive 

investment environment or high political risk, or may be inclined for political reasons to 

favor strategic partnerships for geopolitical influence. 

 
61

12. FISCAL SYSTEM FUNDAMENTALS

12.1. Economic Rent 

Economic rent refers to the difference between the market price of a commodity and the 

opportunity cost in supplying the commodity (Dam, 1976; Johnston, 1994; Seba, 2000), 

or as the difference between the value of production and the cost of extraction, where the 

cost of extraction includes the exploration, development, and operating costs; the cost of 

capital; and a risk premium (Barnett and Morse, 1963; Kemp, 1987; Mommer, 2002a). 

 

Governments attempt to capture as much economic rent as possible through the terms of 

the fiscal regime and taxation structure. There are many ways to extract rent, but none of 

the arrangements is inherently more profitable than any other, and in theory all petroleum 

arrangements can be made fiscally equivalent by adjusting the contract parameters. Once 

the requirements of the structure for the fiscal regime and local law have been identified, 

the negotiating skills and strategies of the parties involved (oil company and host 

government) become a significant determinant of the final contract terms. Oil companies 

were once in a privileged position negotiating with inexperienced foreign governments; 

today host countries are experienced, knowledgeable, and well-educated regarding what 

the market will bear. 

 

12.2. Oil Company and Host Government Objectives 

 

Countries compete to attract foreign investment and seek to maximize the wealth of its 

natural resources, while companies seek to build equity and maximize shareholders’ 

wealth. Most countries compete regionally, while oil companies and NOCs compete 

globally. The motivation of any development agreement is the generation of capital and 

the development of infrastructure. Governments have an obvious economic interest to 

obtain the most beneficial terms, but also must make adequate account of negotiated 

provisions to constituents. Host governments negotiate agreements to accomplish 

objectives, such as provide a fair return to the state and industry, create healthy 

competition and market efficiency, and maximize the revenues related to production. 

12.3. Fiscal Regime 

 

The fiscal regime of a country refers to the policy framework and legal basis for taxation 

or production sharing that governs E&P blocks. The fiscal regime governs the negotiation 

between IOC and HG in the determination of an E&P contract. 

Fears of exploitation, pollution, loss of national pride, and tradition stem from the 

treatment of host countries at the hands of IOCs in the past. Likewise, IOCs harbor a fear 

of expropriation and privatization of their investment which stem from similar incidents 

occurring in the past. 

 

Under a Royalty/Tax system, the contract holder secures exploration rights from a private 

party or government for a specified duration, and development and production rights for 
62

each commercial discovery, subject to the payment of royalty and taxes. The IOC bears 

the full cost and risk of E&P activity, and if no oil is found, the contractor does not 

receive reimbursement for expenses. The earliest concessionary agreements consisted 

only of a royalty. As governments gained experience and bargaining power, royalties 

increased, and various levels of taxation were added. Today, modern concessionary 

systems employ numerous fiscal devices and sophisticated formulas to capture rent. 

 

Under a PSC, governments usually make contracts under powers granted by general 

petroleum legislation and frequently negotiate based on a model contract. Ownership of 

the resource remains with the state, and the IOC is contracted to explore and develop the 

resource in return for a share of the production. The IOC bears the sole cost and risk of 

E&P activity, and only if exploration is successful, will be reimbursed for its cost from a 

share of production. An agreed share of net revenues, referred to as cost oil, is made 

available to the contractor for recovery of exploration, development and operating costs. 

The remaining hydrocarbon revenue, called profit oil, is split according to a negotiated 

formula. The fiscal parameters of a PSC may be subject to bidding or negotiation, and to 

account for various forms of uncertainty, sliding scales are frequently applied. 

12.4. A Brief History of International Arrangements 

 

The earliest international petroleum arrangements were concessions granted at the turn of 

the century (Blinn et al., 1986). The earliest provisions were highly favorable to the oil 

company and included 

• Very large contract areas, 

• Long concession periods, 

• No participation by the host country, 

• No production requirement, and 

• No relinquishment requirement. 

The archetypal Middle Eastern concession was obtained by William D’Arcy from the 

Shah of Persia in 1901. For a $100,000 bonus, $100,000 in stock in his oil company, and 

a 16% royalty, D’Aray received exclusive oil rights to 500,000 square miles of Persia for 

the next 60 years. Other concessions in Saudi Arabia, Abu Dhabi, Kuwait, and Oman 

generally followed the same format (Smith et al., 2000). These concessions did not 

obligate the companies to drill on any of the lands or to release territory if exploration 

and drilling was not undertaken. The host country also had no right to participate in 

managerial decisions and many early concessions freed the companies from all tax 

obligation. Some later concessions granted in the region were even less favorable, 

providing a royalty calculated as a flat rate per ton rather than as a percentage of the 

value of the sale price of production. 

In the mid-1950’s many Middle Eastern contracts were renegotiated and changes in the 

concession format evolved into total or partial ownership by the host government on a 

joint venture basis. Changes in taxation were also introduced. Hybrid fiscal regimes 

combining royalties with tax structures became more common. OPEC was founded in 
63

1960 and sought to control production and prices by changing the balance of bargaining 

power in favor of the producing countries and away from the majors. Renegotiation 

became the vehicle for a substantial restructuring of the traditional concessionary system. 

NOCs were set up to participate in oil ventures as a vehicle for the government to control 

and have greater influence of their natural resources. The level of state participation was 

initially low, but increased with the passage of time. 

In 1966, Indonesia negotiated the first production sharing agreement in response to 

criticism and hostility toward existing concessionary systems. A number of other 

countries followed Indonesia’s lead. 

 

Risk Service (RS) contracts became increasingly popular through the 1980s. In a RS 

contract, the contractor takes on all of the risk and expense of exploring and developing 

production, and in return is paid a negotiated fee per barrel produced. In the 1980’s, 

petroleum arrangements tended toward rate of return based profit sharing contracts. 

Throughout the 1970s and 1980s, governments began experimenting with more direct 

involvement with production. It has been reported that HGs have tended to take larger 

shares of gross profits after the formation of OPEC, and especially, after the price rises of 

1973 and 1979 (Rutledge and Wright, 1998). In the 1990s, countries focused attention on 

international competitiveness and fiscal incentives, and as we move into the 21st century, 

several countries are re-evaluating their fiscal terms in light of sustained high oil prices. 

12.5. Fiscal Systems Vary Over Time, Country, Region, and Field 

Governments respond to market forces in setting terms and conditions for their acreage 

and continually “test” the market, in attempting to renegotiate contracts or revise 

petroleum legislation, and then re-adjusting the terms and negotiation tactics depending 

on investor reaction. In countries with high prospectivity or unstable political 

environments, it is a continuous game of give-and-take. 

 

Countries make use of a broad range of tax and nontax instruments to collect revenue 

from the oil and gas sector, and as one would expect, the strictest fiscal regimes tend to 

be in countries that offer the most attractive geological prospects, combined with fiscal, 

legal, political, and macroeconomic stability. Countries that have a strong reserves base 

and produce more oil than they consume are generally expected to have tighter fiscal 

policies than importing countries with a moderate reserve base. In some countries, a 

single fiscal system applies to the entire industry, while in other countries, a variety of 

fiscal systems may exist. At any point in time, many different contract types are usually 

in force. Every field in the world is unique in terms of its geologic characteristics and 

hydrocarbon chemistry, but also in terms of the conditions that lead to a successful E&P 

contract. Many factors that influence perceptions and negotiation strategies are often 

unobservable or difficult to quantify. 
65

13. FISCAL ELEMENTS

13.1. Concessionary Systems 

In its most basic form, a concessionary system has three components: 

• Royalty, 

• Deduction, and 

• Tax. 

 

The royalty is normally a percentage of the gross revenues of the sale of hydrocarbons 

and can be paid in cash or in kind. Royalty represents a cost of doing business and is thus 

tax-deductible. Deductions include operating expense (Opex), depreciation of capitalized 

assets, amortization, etc. The revenue that remains after the fiscal cost is called taxable 

income: 

Taxable Income = Revenues – Fiscal Cost, 

where, 

Fiscal Cost = Royalty + Opex + Depreciation. 

The definition of fiscal costs is described in the legislation of the country. Royalties and 

operating cost are normally expensed in the year they occur. Depreciation is calculated 

according to the tax legislation. 

Profit is determined as: 

Profit = Revenue – Fiscal Cost – Tax. 

The government’s share of profits, in percentage terms, is called the government “take.” 

Take can assume many forms, depending on the time frame of the analysis and the 

definition employed. Non-profit related elements of government take, such as royalties 

and bonuses, are “regressive” in the sense that they are an up-front cost required prior to 

production. The further downstream from gross revenues a government levies taxes, the 

more “progressive” the system becomes. A simple bonus bid with no royalties or taxes is 

an example of a fiscal system where the government captures economic rent at the time 

of the transfer of rights. Royalties provide a guarantee that the government will benefit in 

the early stages of production. At the opposite extreme is a system based on the taxation 

of profits, where a government takes only if the venture is profitable. Most systems fall 

in-between the two extremes (Gao, 1994; Kemp, 1987; Mikesell and Bartsch, 1971; 

Mommer, 1999). 
66

13.2. Contractual Systems 

In a production sharing contract, exploration is performed by the operating company at its 

own risk and can only be recovered from future production. This feature is not unlike the 

risk associated with normal exploration, but the difference arises in how expenditures are 

recovered if reserves are found and the manner in which reserves are split between the 

host country and the company. If petroleum reserves are discovered, they are almost 

always owned by the host government, but the production is split between the host 

government and the company according to a negotiated formula. 

The production sharing agreement divides production between the government and the 

contractor after allowing a portion for cost recovery. A PSA typically imposes a lower 

income tax and royalty, and in its most basic form, has four components: 

• Royalty, 

• Cost Recovery, 

• Profit Oil, and 

• Tax. 

 

The oil company pays a royalty on gross production to the government and is then 

entitled to a pre-specified share of production for cost recovery. The remainder of the 

production is shared between government and the oil company at a stipulated amount. 

The oil company has to pay income tax on its share of profit oil. 

Two basic service contracts exist, the “full risk” service contract and the “normal” service 

contract. In a normal service contract, the company agrees to perform a certain amount of 

exploration work in a specified area. The oil company is reimbursed for cost incurred and 

may be paid a bonus if it discovers reserves. In a full risk service contract, the exploration 

and development expenditures are generally converted to a loan which is repaid in cash 

installments based on cash flows from all or a specified portion of production. 
67

14. LICENSING AND NEGOTIATION 

An E&P contract is a legal instrument written between two parties – an oil company and 

a mineral rights owner – that describe the terms and conditions of exploration and 

production. The terms and conditions of the contract are negotiated to satisfy each party, 

are written before exploration has occurred, and hold for all fields discovered on the 

block that are declared commercial within the exploration period of the contract. 

Geologists and engineers estimate the geologic potential and hypothesize field sizes that 

may reside within the contract area based on preliminary “data packages.” Basic seismic 

data is usually available from the government for a fixed fee, and a prospective bidder 

may have proprietary data on the block or nearby acreage. From a hypothetical field size 

distribution, the bid parameters and work program of the contract is determined. 

 The mineral rights owner is frequently a sovereign nation and the process begins when 

the HG announces a license round and divides prospective acreage into contract areas 

(license blocks). The IOC evaluates exploration and development scenarios for 

individual blocks based on information provided by the HG and other sources. Technical 

and commercial bids are prepared consistent with the prospectivity, strategic objectives, 

and capital budget of the firm: 

• Technical bids specify the work commitment W to be performed, describing 

the seismic work (in kilometers), the number of wells to be drilled (by type 

and total footage), and/or the total expenditures to be spent within the block. 

• Commercial bids specify the biddable parameters of the fiscal regime F which 

will govern operations if exploratory activities find commercial quantities of 

resource. 

 

The work commitment is a certain event, while the terms of the fiscal system only hold if 

a discovery is declared commercial. 

 

To determine the bid parameters, the IOC conducts scenario (“what if”) analysis to assess 

the risk-reward criteria of the bid. The work program is taken at the sole risk and cost of 

the IOC, and if exploration is unsuccessful, the HG does not reimburse the IOC for cost 

expensed. If the exploratory program finds hydrocarbons, then the size and complexity of 

the field(s) within the block, as well as a number of other factors, such as existing 

infrastructure, oil quality, geologic complexity, fiscal terms, operating conditions, etc., 

will determine if the field is commercial. If block B has a hypothetical field distribution 

{ f1 ,..., fk }, with field fi having an estimated present value11 of PVi(F,W) and probability 

of discover, pi(W), then the present value of the block is Σpi(W)PVi(F,W). The IOC will 

 

11 The value of a petroleum property – whether producing or unexplored – is typically computed as the 

discounted cash flow of a projected cash flow stream. The discount rate determines the relative weight to 

be given to each flows received at different times and depends upon the property type and owner. 

Typically, properties developed by major U.S. producers employ discount rates in the range 8-14%, but 

smaller producers or projects in foreign lands, may be deemed riskier and require a higher discount. 

Expectations of price and cost fluctuations and other non-diversifiable sources of risk (such as political 

risk) also influence the selection of the discount rate. 
68

select values of F and W such that the present value of the work program is less than the 

expected reward of discovery, PV(W) < Σ pi(W)PVi(F,W). 

The HG compares the bids received to determine the most favorable contracts based on 

the proposed work commitment, (Wi, Fi), i = 1, ..., q; the technical standing, experience, 

capabilities, past business practices, and financial position of the IOC; and previous 

experience and success in exploration in the area or similar areas. 

 

The work program is usually easy to evaluate since it refers to the seismic acquisition, 

drilling requirements, and/or total expenditures to be made. The present value of the work 

program is computed and used to compare contractor commitment. Evaluation of the 

fiscal terms is more complicated, since it is based on conditions that are uncertain 

(discovery, commerciality, reserve size, field characteristics, etc.) as well as specific 

assumptions of each bidder. Host governments attempt to balance the tradeoffs involved 

in selecting a large work commitment and poor fiscal terms versus a small work 

commitment but more favorable fiscal parameters. In negotiation, the HG and IOC must 

achieve a balance between maximizing reward and minimizing risk. The HG will need to 

weight its desire to maximize short-term revenue against any deterrent effects this may 

have on investment. The IOC will need to weight the risk capital against the reward 

potential subject to its capital budget constraints and strategic objectives. 

The IOC(s) with the most favorable terms are short listed for further negotiation. The HG 

and IOC negotiate the final terms of the contract (the work program and fiscal regime) 

such that the economic, development, and socioeconomic objectives of each party are 

satisfied. Terms are suggested by the contractor to enhance their objective functions. 

These terms are evaluated by the host government and approved, rejected, or countered. 

The process is continued until either a mutually agreeable set of terms is determined, in 

which case a deal is made, or agreement cannot be reached and the deal is dead or 

negotiation resumes at a later date. After both parties sign the contract, the terms and 

conditions are generally not subject to re-negotiation unless by mutual consent. Unilateral 

action (say, by government decree) is a mild form of nationalization, and although not 

necessarily illegal by international law, is considered bad business practice. 
69

15. FACTORS THAT IMPACT E&P CONTRACT STRUCTURE 

 

15.1. Categorization 

 

Many factors influence the type of contract a country adopts in E&P activity. Many more 

factors impact the terms and conditions of the contracts that are actually negotiated. To 

understand the variations that are possible, it is useful to consider general classification 

categories and then enumerate factors believed to be relevant (Table A.26). The factor 

lists are not exhaustive, and usually reflect data availability, analyst preference, economic 

fundamentals, and other factors. 

15.1.1. Geologic Prospectivity: Geologic prospectivity refers to the capability of an area 

to host commercial quantities of hydrocarbons. There are many different and independent 

factors that indicate geologic potential and prospectivity, including proved reserves, 

proved and probable reserves, undiscovered resources, reserves additions, current 

production, R/P ratio, and average field size. 

15.1.2. Technical Prospectivity: Technical prospectivity refers to the economic and 

geologic conditions that characterize E&P activity on a field or area-wide basis, such as 

delineations according to onshore/offshore, frontier/mature, shallow/deep/ultradeep 

water, deep/ultradeep drilling horizon categories, etc. This is a broadly defined category 

and includes attributes such as finding and development costs, oil company participation, 

production maturity, and many other variables. 

15.1.3. Country Prospectivity: Country prospectivity describes the economic and 

political conditions which impact a country’s bargaining position in contract negotiation. 

Many factors characterize country prospectivity, and some of the major factors include: 

GDP per capita (economic strength), oil revenue per GDP (oil dependence), oil price risk 

premium (oil dependence), foreign direct investment (economic strength), E&P 

investment capital (investor interest), import/export status (bargaining position), 

macroeconomic stability (economic strength), company type (bargaining position), 

corruption index (bargaining position), economic system, regional prospectivity, country 

history, IOC participation, investment climate, political risk, degree of competition, and 

number of successful producing projects. 

15.1.4. Geopolitical Prospectivity: Geopolitical prospectivity refers both to the political 

risk involved with investment, such as repatriation, nationalization, supply disruption, 

war, riots, contract renegotiation, and changing laws, and the political aims of the 

government leadership such as strengthening political relationships with a country 

through economic cooperation, positioning NOC as a geopolitical tool, etc. 

 

15.1.5. Legal Prospectivity: Legal prospectivity refers to a country’s respect for the rule 

of law, legislative complexity, legislative maturity, stability of contract terms, and the 

nature and frequency of changes in the petroleum legislation. 
70

15.2. Factor Description 

For a general category, each factor may be proxied by one or more variables, with the 

selection governed by data availability, user preference, economic theory, or other 

conditions. Unobservable factors need to be inferred, usually have a higher degree of 

uncertainty, and are less reliable in application. All proxies are noisy and do not 

necessarily provide a correlation between a factor and measure. 

15.2.1. Reserves Additions: Proved reserves can be augmented through exploration and 

development of new discoveries, through technological improvements, as well as the 

existence of more favorable economic conditions. Reserves additions represent the 

change in proved reserves over a period of time, and are linked in an uncertain manner, to 

the amount of investment. 

 

15.2.2. R/P Ratio: The reserves-to-production (R/P) ratio is a measure of the potential 

availability of a resource over time. The R/P ratio describes the proved reserves inventory 

of an entity (e.g., company, country, region, world) at a specific point in time divided by 

the production rate at the same time. The R/P ratio is normally interpreted as the number 

of years that the existent reserves base can sustain the current level of production. 

 

The uncertainty of R/P is small, since both the numerator and denominator term are 

reasonably well known quantities, but the ratio itself contains less information than it 

might suggest. For example, an oil producing country with low reserves (R) but even 

lower production (P) may exhibit a relatively large R/P (e.g., Italy, Tunisia) which does 

not correlate to prospectivity. In other cases, R/P may increase because of production 

decline; e.g., the U.S. R/P ratio increased from 7.7 in 1993 to 11.3 in 2003 primarily 

because U.S. production has declined by about 1 million BPD through the decade, not 

because of advances in discovery. Countries with high R/P may or may not be exporting 

countries. 

15.2.3. Finding and Development Cost: The cost to find and develop oil and gas is one 

of the most common business performance measures in evaluating companies and 

comparing oil-producing regions. Unfortunately, simple numerical measures usually do a 

poor job of adequately capturing the complexity of the E&P process. Finding and 

development (F&D) costs vary over time, by company, country, and region, and this 

hierarchy dictates the manner in which F&D costs are categorized. It is generally not 

possible to trace expenditures in a direct fashion from exploration to field development. 

Finding and developing costs for a country are frequently computed as a weighted (or 

simple) average of all (or a sample) of the companies operating in the country. 

 

15.2.4. Country E&P History: A government’s track record can be measured by a 

number of proxies, such as the number of licensing rounds it has performed, years of 

production, the number of IOCs involved in a license round and/or production, 

competency of the country to administer a tax system, legislative maturity, investment 

climate, etc. Many of these measures are subjective indices which may or may not 

provide a useful descriptive proxy. 
71

15.2.5. Industry Structure: IOCs may be classified in terms of their size via reserves 

base or market capitalization, operational areas, degree of vertical integration, or any of 

several other measures. NOCs may be classified in terms of their OPEC membership, 

demand or supply nature, operational areas, or economic strength. 

15.2.6. Economic Strength: The economic strength of a country and the experience of 

the NOC provide an indicator of the relative bargaining position of the country in 

negotiation with the IOC. Economic strength can be measured in absolute (e.g., GDP) or 

relative terms (GDP per capita). 

 

15.2.7. Economic Growth: Economic growth in oil producing nations increase the 

country demand for oil which can be satisfied by local production. Nations whose oil 

exporting sector is a major component of their GDP are typically led by the expansion of 

the sector. High oil prices create an inflow of oil demand revenue increasing GDP 

growth. 

 

15.2.8. Oil Price Risk: If a government obtains substantial revenue from oil production 

and exports, changes in oil prices will have an impact on revenues generated (Table 

A.27). Oil price risk is the contribution that changes in oil prices makes to the variance in 

GDP – the greater the contribution, the greater the premium. 

 

15.2.9. Oil Intensity: Oil intensity is defined as the consumption of oil per $1000 of 

GDP. Net oil trade as a percent of GDP is another potentially relevant indicator, since as 

the proportion of oil revenues increases, the host country is likely to want increasing 

control over this part of their economy. 

15.3. Fiscal Systems Are Governed by Multiple Trade-Offs 

Fiscal systems are governed through multiple trade-offs. If a region has “significant” 

prospectivity, and the legal, fiscal, and geopolitical factors are “acceptable,” then the 

region should be successful in attracting investment into the E&P sector. If the region 

observes declining technical prospectivity, then enhanced legal, fiscal, and geopolitical 

factors may be employed to balance the system. If a frontier region does not draw IOC 

interest, the HG and IOC will likely pursue a “weak fiscal system, large work program” 

policy. For a region with recent discoveries and perceived good prospectivity, a “strong 

fiscal system, small work program” policy would be more likely to prevail. Perceptions 

and expectations play an important role in negotiation. 

The impact of unobservable factors is difficult to ascertain, but are believed to be just as 

relevant. Contract negotiations may take place over one or more years, and during this 

time, E&P activity may occur in the region and influence the perceptions of the 

negotiating team while the global economic environment may improve or deteriorate. If a 

series of dry wells are publicly announced, or an initial exploratory well is a spectacular 

success, this may impact the terms and conditions of negotiation. The historic and 

personal relationships that exist between IOC and HG personnel are additional factors 

that influence the terms and conditions that are ultimately determined. 
72

The relationship between the factors that describe and characterize a fiscal system and the 

fiscal terms observed in signed contracts follow readily discernable hypothesis, but the 

veracity of the results need to be continually probed and questioned. Factor relations are 

tested by asking the question: “How do we expect a fiscal system to be perceived by an 

investor for a factor with a ‘high’ versus a ‘low’ value while holding ‘all other factors 

constant’?” 

• A region with a high geologic prospectivity, as measured by proved reserves 

or production rate, will likely have tougher terms than a region with a low 

geologic prospectivity, for all other factors constant. 

• Countries that are net exporters will likely set tougher conditions on the terms 

and conditions of exploration relative to net importing countries. A region 

with a high F&D cost will likely offer better terms than a low F&D cost 

region. 

• Frontier acreage is expected to offer better terms because of the additional risk 

and uncertainty associated with exploration, while for a mature region (as 

measured, say, by the number of years past peak production), the sign is likely 

to be ambiguous – the potential for large discoveries is reduced, but this may 

be balanced by greater regulatory certainty and infrastructure and service 

networks that will keep development costs down12. 

• If a government obtains substantial revenue from oil production and exports, 

changes in oil prices will have an impact on revenues generated and may 

impact fiscal terms, both current and future contracts, but the direction of the 

impact is difficult to ascertain. It is expected that countries with a high oil 

price risk premium will have more lenient terms, for other factors constant, 

and as the proportion of oil revenues increase, the host country may desire to 

exert greater control. 

• The size of a company, its economic strength, international experience, and 

strategic objectives play an important role in contract negotiations. The role 

and power of the NOC, local/global experience, participation requirements, 

and relationship with the IOC are additional factors that influence contract 

terms. 

• The bargaining position of a company is directly correlated with its size and 

experience. NOCs bargaining position is related to its economic strength, 

experience, and other country-specific characteristics. 

 

12 For example, the U.S. Gulf of Mexico is a relatively high-cost production area at $10-15/BOE (compared 

to $2-5/BOE Middle East production) with a deepwater environment that is one of the harshest in the world 

and environmental and safety regulations regularly enforced. On the other hand, the GOM also has a welldeveloped infrastructure, a host of well-positioned professional service companies, reasonable royalty and 

tax requirements, and creative incentive programs that continues to make the region attractive to 

investment. 
73

• Royalty/Tax systems are the oldest in the world, and due to political, 

historical, and other conditions, if a country has been under such a system for 

a length of time, momentum may maintain the framework with adjustments 

being made to the terms of the contract. PSCs are likely to be the preferred 

contract type in new acreage rounds. 
75

16. CONTRACT SELECTION

16.1. Data Source 

The type of contracts countries use to govern their E&P industry are observable features 

obtained either by examining a country’s petroleum legislation or by reviewing the 

contracts that are signed in a license round. The principal source of information regarding 

petroleum laws and contracts is published by Barrows (www.barrowscompany.com). 

Barrows divides the world into six regions and charges $7,900/region ($2,950/region 

renewal price) for a listing of laws and contracts concluded through the year. A summary 

of typical model oil contracts is also available in a Petroleum Concession Handbook for 

$5,400 ($2,700 renewal). An overview of countries petroleum laws and investment 

climate, tax, and model contracts can be purchased for $6,000. Contracts and 

participation agreements in which governments have formed joint ventures are also 

available in various other, usually dated, publications; e.g., (Barrows, 1983; Barrows, 

1994; Johnston, 1994; Mikesell, 1984; Mommer, 2002b; Taverne, 1994; Smith et al., 

2000; Wood, 1993). 

 

16.2. Categorization 

There are many ways to characterize and describe the choice of contract a country 

employs. The most accurate approach is a comprehensive historic review of the country’s 

economic, political, and geologic prospects. Another approach is to select a few 

distinguishing features that can be used as factor descriptors. The former approach is best 

suited for a country study, but is usually not appropriate for a regional or global analysis. 

The factor approach has much to recommend it since it is direct, relatively 

straightforward, and provides a suitable framework for discussion. The main weakness is 

that the assessment is only capable of incorporating a few distinguishing factors, and 

often in a simplistic, causal manner. The factor approach is thus limited in its ability to 

capture all the variability that is observed, and so a carefully defined framework is often 

necessary in analysis. Some examples of classification systems illustrate their application 

and pitfalls. 

16.2.1. One Factor: One of the simplest factors to consider in contract selection is the 

development status of the country (Table A.28). Industrialized countries have tended to 

rely on Royalty/Tax systems, while PSCs are the primary choice for many developing 

countries, especially those opening up new areas for exploration or revising their 

petroleum legislation. 

 

The political system of a country may be used to classify fiscal regimes according to 

political and institutional features; e.g., mature democracies, factional democracies, 

paternalistic autocracies, predatory autocracies, or reformist autocracies (Table A.29). 

Economic systems are generally linked with political systems, but may also be 

considered separately. Bunter (2002) applies a regional classification as follows (Table 

A.30): 
76

• Industrialized. Developed economies are classified as laissez faire (lack of 

government intervention) and dirigiste (directed economies). In laissez faire 

economies, there is a strong rule of law with the terms/conditions of E&P 

generally favorable. In dirigiste economies, the state is viewed as protection 

against business and state oil companies as proprietor and custodian of the 

nation’s resources. In dirigiste economies, access may be limited to the NOC, 

and if access is open, the fiscal terms are expected to be more stringent. In 

both developed and dirigiste economies, Royalty/Tax systems are standard; 

PSCs and resource rent tax (RRT)-based systems are rare. 

• OPEC. In “rich” OPEC countries, there is a powerful NOC and the IOC 

serves as a contractor under Service Contracts with limited access. The E&P 

terms are tough with little upside potential. In “less rich” OPEC countries, the 

NOC is less powerful and foreign investment is required. E&P contracts in 

these countries are more conducive to investment, but the risk premium is also 

higher. 

• FSU. Russia and FSU countries have generally been resistant to foreign 

partners, and in recent years, Russia has made the decision to 

consolidate/monopolize its energy empire which will further restrict foreign 

investment. The rule of law is still not firmly established in the region, and 

corruption levels are similar to many less rich OPEC countries. The presence 

of significant oil and gas resources means that E&P terms are tough. FSU 

countries with good prospectivity such as Kazakhstan, Uzbekistan, and 

Turkmenistan have been more open to foreign investment, at least in their 

initial license rounds, but their close geographic proximity to Russia and 

China is likely to lead to more limited access for western investment in the 

future. FSU countries with modest or low prospectivity such as Tajikistan, 

Kygisistan, Ukraine, and Belarus have more favorable E&P terms. A variety 

of systems have been employed throughout FSU countries. 

• Africa. In Africa, about half of the countries rely on PSCs, and the other half a 

profit-based Royalty/Tax system with a resource rent tax. Periodic crises keep 

the risk premium in several African countries high. 

• Asia. In Asia, PSCs are widespread, due to Indonesia’s influence in creating 

the first PSC in 1966. Only a few countries in Asia apply RRT-based systems. 

16.2.2. Two or More Factors: Countries that have a strong reserves base and produce 

more oil than they consume are expected to have tighter fiscal policies than importing 

countries with a moderate reserve base. A two-factor model using “economic strength” 

and “oil supply balance” under two subcategories (economic strength and supply 

balance) is shown in Table A.31. Production Sharing Contracts are applied under all 

combinations of conditions. Joint ventures find application in weak exporting countries 

and in strong importing countries. Risk contracts tend to be applied in economically weak 

oil importing countries, and service contracts in strong exporting countries (e.g., Saudi 
77

Arabia, Kuwait), although Mexico also employs service contracts but is not a strong 

exporter. Multiple factors can be adopted in a regression modeling framework to help 

explain contract type and terms, but the weak correspondence, noisy proxies, and the 

multiple correlating factors imply that analytic models will at best only partially explain 

the variability that is observed. 
79

17. CONTRACT TERMS, CONDITIONS, COMPARISONS

17.1. Negotiating Contract Terms 

The terms and conditions of a contract are negotiated between two parties, at a specific 

point in time, and for specific acreage. The parties to the negotiation have a unique 

history; with different experiences, strengths, weaknesses, and objectives; and their own 

perception of the prospectivity of the region and investment risk. The confluence and 

interaction of these factors, many of which are unobservable and not conducive to 

quantitative analysis, will mean that the determination of a primary factor set to assess 

and compare contract terms and conditions is unlikely to be completely successful. 

Contracts need to be examined on an individual basis, and if “trends” and “patterns” in a 

country or region are to be believed, a careful analytic framework needs to be developed. 

17.2. Measurement Issues

A number of measurement problems exist in regard to data acquisition and assessment. 

The terms and conditions of contracts in many countries are governed by nondisclosure 

clauses, and thus, are generally unobservable. Under PSCs, governments will make 

contracts under powers granted by general petroleum legislation and negotiate from a 

model contract. Model contracts are publicly available or for purchase, but they do not 

represent the final negotiated contract. Model contracts are merely the starting point of 

negotiation, and thus use or comparison of a model contract will necessarily introduce 

bias. Signed contracts are the ideal data instruments to employ, but they can usually only 

be acquired at a significant fee or through private contact. To ensure a representative 

sample for a country, region, or period of time, several contracts should be examined. 

Mixing model and signed contracts is not considered good methodological practice, but 

may be necessitated because of sparse data availability. 

A number of additional assumptions and inferences are required in assessment which 

complicates and distorts the analysis. An E&P contract is composed of numerous terms 

and conditions which may be difficult, if not impossible, to compare on an individual 

basis, and it is the collection of terms (in total) that “make” the contract. If the structure 

of contracts are stable, we could examine individual terms (royalty, tax, profit oil, etc.) 

and map how they change over time, across firms and regions. The problem with this 

approach is that multiple terms can change in different directions, and it is really the 

aggregate of all the contract changes that impact project economics and not the change in 

any individual term. 

 

Fiscal terms are frequently multidimensional and nonlinear, and so in general, one-factor 

models will not suffice. An alternative method is to attempt to characterize the fiscal 

system in one (or a few) numerical measures that describe the impact of the system. 

“Take” is a metric that is frequently used for this purpose. 
80

17.3. Take Measure 

Take is the most common method to compare fiscal systems, and like many other (onedimensional) metrics, is frequently misapplied and misunderstood (Johnston, 2002). Data 

on government take for projects and countries are readily available, but their calculation 

and interpretation is subject to a high degree of uncertainty which is frequently ignored or 

miss-specified. 

 There are two methodological approaches to the computation of take. We can apply 

“standard field conditions” to a given fiscal system and assess the fiscal regime 

indirectly, or we can attempt to compute the expected value of take ex-ante under 

“specific field conditions” that are known or expected to hold for the field. Strengths and 

weaknesses are associated with each approach. 

17.3.1. Standard Field Conditions: Under standard field conditions, a given field size 

(e.g., 100, 250, 500, 1000 MMbbl) is evaluated under the fiscal system with respect to a 

common set of assumptions on oil price, development cost, production cost, etc. relative 

to a model contract. The common parameters obviate the need to acquire or estimate 

conditions specific to the development strategy, but introduce bias in the gross 

approximation. Economic yardsticks such as present value, rate of return, and take. are 

computed for each field size and then combined according to the specified distribution. 

VanMeurs uses a point-system to classify fiscal systems into five groups, from “very 

favorable” (five-point) to “very tough” (one point), while Johnston and others compare 

undiscounted and discounted take as the system metric (Table A.32). The analysis in both 

cases is under standard field conditions and is performed prior to discovery, and thus, is 

governed by a large degree of uncertainty. Take computations under standard field 

conditions are also referred to as pre-discovery assessments. 

17.3.2. Specific Field Conditions: Under specified field conditions, take is computed 

based on a combination of actual and estimated field conditions, using either a signed or 

model contract. The commercial service providers IHS, Petroconsultants, 

WoodMacKenzie, and others (Smith, 1993; Kaiser and Pulsipher, 2004) have followed 

this approach. Commercial databases provide actual and model contract terms, 

development costs based on engineering estimates, fiscal economics, and related cost 

statistics. The take statistic under specific field conditions would generally be considered 

a more accurate and reliable indicator if performed post-discovery. Even under specified 

field conditions, however, a significant amount of variation is still expected to occur 

under this approach. 

17.4. Many Different Notions of Take Exist 

The value, uncertainty, and conceptual basis of take varies throughout the life of a field, 

beginning from the first stages of assessment in preparation of bid submission, to 

successful negotiation, discovery, commerciality, production, and eventually, 

abandonment (Table A.33). 
81

17.4.1. Bid Submission: To determine the parameters in preparation of bid submission, 

the IOC conducts scenario analysis under different field sizes, fiscal terms and work 

program commitments. Project economics (and take) are evaluated. All system metrics, 

including take, are highly uncertain at this point in time because the computation is based 

on hypothetical conditions supported by limited and often incomplete data. 

17.4.2. Negotiation and Award: If the IOC bid submission is accepted, further 

negotiation will typically occur until a mutually agreeable set of terms is determined. 

After negotiations are complete and the contract signed, the IOC considers the fiscal 

terms fixed. The uncertainty associated with discovery and the exogenous environment 

will determine the uncertainty of the computation. 

17.4.3. Discovery: If hydrocarbons are discovered in commercial quantities on the tract, 

then the take statistic can be computed with a higher level of certainty. The field size 

distribution is presumably known, the production schedule and development cost can be 

assessed under known assumptions, and the tax and non-tax instruments were previously 

negotiated. 

17.4.4. Production: With first production, the revenue and cost structure are much better 

understood, and the take statistic can be computed with a higher degree of certainty. 

Going forward from first production through depletion the level of uncertainty is 

expected to decrease, although the stability of the take statistic is dependent on the HG 

not initiating unilateral changes in the fiscal terms. 

17.4.5. Abandonment: At abandonment and under conditions of perfect information, a 

“look-back” (post-mortem) analysis will determine the exact value of take. In theory, cost 

and revenues are known precisely, and under known terms of the fiscal system, take can 

be computed with a high degree of precision. 

17.5. Summary of Take Characteristics 

 

• Take is a multidimensional, nonlinear function of variables that are uncertain 

and unobservable. 

• If the terms and conditions of the fiscal system are known, then only at the 

end of the productive life of a field, when all the production and cost statistics 

are also known, can the value of take be computed with certainty. 

• In all other situations, either because the terms of the fiscal system or the field 

parameters are not known, or only known under conditions of uncertainty, the 

level of uncertainty associated with take is governed by the time of assessment 

(pre-discovery, post discovery) and availability of data. 

• Take statistics are uncertain, and depending upon the time of assessment, can 

be highly uncertain. “Look-back” analysis is rarely performed by industry, 

since at the end of the life of a field, the value of take has little commercial 

value. 
82

• Take statistics are provided by various commercial vendors, but use and 

comparison of the data must be based upon careful assessment and clear 

knowledge of the assumptions involved. 

17.6. Production Sharing Agreement Statistics 

Rutledge and Wright claim that a 50:50 split between government and contractor take 

was considered a fair value before the mid 1970s, and in a study performed by 

Petroconsultants in 1995 showed that in more than 90% of 110 countries examined, 

government take ranged from 55%-75%. Mommer and others has shown similar levels of 

taxation (Mommer, 2002a). 

In a 1998 study, Bindemann examined 268 PSAs signed by 74 countries over the period 

1966-1998. Each contract was defined with respect to the parties involved in the 

arrangement (host country, foreign partner(s)), the year the contract was signed, the 

location (onshore, offshore) of the field, and several other factors. 

 

The royalty rate and cost of oil are reported as the maximum rates while profit oil shares 

are reported in terms of the minimum and maximum values. Signature and production 

bonuses are described in U.S. dollars. A summary of the main results are depicted in 

Table A.34. The results “support” most of assumptions concerning on-shore vs. off-shore 

regions, import vs. export countries, and regional prospectivity; e.g., royalty rates and 

signature bonuses for offshore regions and import nations tend to be slightly smaller 

(more generous) than on-shore regions and export nations, and trends in royalty and 

maximum cost oil have increased over time. 

The results of the study should nonetheless be interpreted with caution, for several 

reasons: 

• The sample set Bindemann employed is not well defined, and its relation to 

the set of all contracts not described. 

• “Model” contracts are frequently used in analysis, but most parameters of 

model contracts are subject to negotiation or may be biddable, and are not

expected to be representative of actual contracts. Significant bias will be 

introduced into analysis when using model contracts. 

• The field characterizations which define the nature of the contracts 

(“onshore/offshore,” “import/export”) is not described. 

• PSA’s employ contracts with sliding royalty scales and cost oil which require 

knowledge of the (expected) production of the field. Most profit oil shares are 

also subject to a sliding scale based on output or return which was not 

considered in the model framework. 

Fiscal comparisons are difficult to perform for many reasons, some of which are 

highlighted in the Bindemann study, but which are common across several other analytic 

studies. 
83

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APPENDIX 

TABLES AND FIGURES
93

Table A.1 

 Various Risks Exist in Oil and Gas Investment 

 

Risk Category Type 

Economic Market 

Construction 

Operation 

Macroeconomic 

Geologic Reserve 

Production 

Political Regulatory 

Transfer-of-profit 

Expropriation/nationalization 

Legal Contract 

Jurisdictional 

Force majeure Natural disaster 

Civil unrest 

Strikes 

Terrorism 

Table A.2 

 Examples of Integrated Companies Classified According to Geographic Operation 

International U.S. Integrated Canadian Integrated Non-North American 

BP Amerada Hess Husky Energy BASF A.G. 

Chevron ConocoPhillips Imperial Oil BG Group 

Exxon Mobil Murphy Oil Petro Canada BHP Billiton 

Royal Dutch Shell Marathan Oil Suncor Energy ENI 

Total Lukoil 

 MOL 

 Petrobras 

 Petrochina 

 Petro Kazakhstan 

 Petroleos Mexicanos 

 Repsol 

 Sinopec 

 Statoil 
94

Table A.3 

 Examples of Independent Companies Classified According to Size and Geographic Ope

International Large U.S. Mid-Sized U.S. Small-U.S. NonAnadarko Petroleum Cabot Oil & Gas Berry Petroleum Harken Energy Cairn Apache Chesapeake Energy Comstock Resources McMoRan Exploration ChapBurlington Resources Forest Oil Denbury Resources Meridian Resources CNODevon Energy Newfield Exploration Energy Partners PetroQuest Energy GlobEnCana Noble Energy Houston Exploration Remington Oil & Gas NelsEOG Resources Pogo Producing Magnum Hunter Resources Tetra Technologies TranKerr-McGee Vintage Petroleum Stone Energy W&T Offshore VentNexen Occidental Petroleum 

XTO Energy Swift Energy Woo

Talisman Energy Unocal 
95

Table A.4 

 Selected National Oil Companies 

Country Company 

Abu Dhabi ADNOC 

Algeria Sonatrach 

Angola Sonangol 

Azerbaijan Socar 

Bahrian Bahrain National Oil (BNOC) 

Bolivia Y.P.F.B. 

Brazil Petroleo Brasileiro SA (Petrobras) 

Canada PetroCanada 

China China National Petroleum Co. (CNPC) 

China National Offshore Oil Co. (CNOOC) 

Sinopec 

Columbia Ecopetrol 

Dubai Dubai Petroleum Co. (DPC) 

Ecuador Petroleos del Ecuador 

Egypt Egyptian General Petroleum Corp. (EGPC) 

Hungary Hungarian Oil and Gas Co. (MOL) 

Indonesia Petramina 

India India Oil Corp. (IOC); Oil and Natural Gas Co. (ONGC) 

Iran National Iranian Oil Co. (NIOC) 

Iraq Iraq National Oil Co. (INOC) 

Japan Japan National Oil Co. (JNOC) 

Kazakhstan Kazmunaigaz (KMG) 

Korea Korean National Oil Corp. (KNOC) 

Kuwait Kuwait Petroleum Corp. (KPC) 

Libya National Oil Co. (NOC) 

Malaysia Petronas 

Mexico Petroleos Mexcanos (Pemex) 

Nigeria Nigeria National Petroleum Co. (NNPC) 

Norway Norsk Hydro ASA; Statoil 

Oman Petroleum Development Oman LLC 

Peru Petroperu 

Qatar Qatar Petroleum Corp. (QP) 

Romania Romanian National Oil Co. (Petrom) 

Russia Rosneft; Gazprom 

Saudi Arabia Saudi Arabria Oil Co. (Saudi Aramco) 

Trinidad & Tobago Petroleum Co. of Trinidad & Tobago Ltd. (Petrotrin) 

Turkey Turkish Petroleum Co. (TPAO) 

UAE ENOC 

Venezuela Petroleos de Venezuela SA (PDVSA) 
96

 Table A.5 

 Top 10 Oil and Gas Company Rankings – Oil (2006) 

Rank Company 

Reserves 

(Billion BOE) Company 

Production 

(MBOE/day) 

1 S. Aramco 262.7 S. Aramco 9,830 

2 NIOC 132.5 NIOC 4,081 

3 INOC 115.0 Pemex 3,754 

4 KPC 89.4 PDVSA 2,600 

5 PDVSA 77.1 Exxon Mobil 2,571 

6 ADNOC 52.6 BP 2,531 

7 Libya NOC 28.8 KPC 2,424 

8 NNPC 21.2 Royal Dutch Shell 2,333 

9 Lukoil 15.9 PetroChina 2,124 

10 Pemex 14.8 INOC 2,027 

 Table A.6 

 Top 10 Oil and Gas Company Rankings – Oil & Gas (2006) 

Rank Company 

Reserves 

(Billion BOE) Company 

Production 

(MBOE/day) 

1 NIOC 307.2 S. Aramco 10,944 

2 S. Aramco 305.6 Gazprom 9,704 

3 Gazprom 219.6 NIOC 5,569 

4 INOC 135.1 Pemex 4,360 

5 QP 128.9 Exxon Mobil 4,347 

6 PDV 104.1 BP 4,062 

7 KPC 99.4 Royal Dutch Shell 3,918 

8 ADNOC 71.6 PDVSA 3,320 

9 NNPC 40.2 Sonatrach 3,093 

10 Sonatrach 37.9 PetroChina 2,625 
97

Table A.7 

 Percentage Yields of Refined Petroleum Products from Crude Oil in the U.S., 

 1964-2003 (%) 

 1964 1974 1984 1994 2003 

Gasoline 44.1 45.9 46.7 45.7 46.9 

Distillate fuel oil 22.8 21.8 21.5 22.3 23.7 

Resid, fuel oil 8.2 8.7 7.1 5.7 4.2 

Jet fuel 5.6 6.8 9.1 10.1 9.5 

Coke 2.6 2.8 3.5 4.3 5.1 

Asphalt 3.4 3.7 3.1 3.1 3.2 

Liquefied gases 3.3 2.6 1.9 4.2 4.2 

Total (%) 90.1 92.3 92.9 95.4 96.8 

 Source: (EIA, 2005). 

Table A.8 

 U.S. Proven Reserves and Undiscovered Resources 

 Oil (Bbbl) Natural Gas (Tcf) BOE (Bbbl) 

Region F95 Mean F5 F95 Mean F5 F95 Mean F5 

Alaska OCS 8.66 26.61 55.14 48.28 132.06 279.62 17.25 50.11 104.89

Atlantic OCS 1.12 3.82 7.57 14.30 36.99 66.46 3.67 10.40 19.39

Gulf of Mexico OCS 41.21 44.92 49.11 218.83 232.54 249.08 80.15 86.30 93.43

Pacific OCS 7.55 10.53 13.94 13.28 18.29 24.12 9.91 13.79 18.24

Total U.S. OCS 60.60 85.88 115.13 326.40 419.88 565.87 124.68 160.60 215.82

Source: (USDOI, MMS, 2006). 

Note: F95 indicates 95% chance of at least the amount listed, F5 indicates a 5% chance of at least the 

amount listed. Only mean values are additive. 

Table A.9 

 World Proven Reserves and Undiscovered Resources 

 World United States 

Oil 1,293 Bbbl 23 Bbbl 

Natural Gas 6,112 Tcf 187 Tcf 

Coal 1.08 T tons 0.27 T tons 

Oil (Tar) Sands 272 Bbbl 22 Bbbl 

Shale Oil 2,570 Bbbl 20 Bbbl 

 Source: (World Energy Council, 2003).
98

Table A.10 

World Proven Reserves (2004) and Undiscovered Resources (2000) 

Oil – Billion barrels (Bbbl) 

Region Proven Undiscovered Resources 

Reserves F95 F5 Mean 

USA 22,446 60,500 94,700 75,600 

North America 40,268 67,302 252,190 146,091 

FSU 79.4 35,601 225,654 115,985 

Middle East and North Africa 743.4 73,286 423,178 229,882 

Asia Pacific 35.9 8,726 58,653 29,780 

South Asia 5,735 1,032 6,957 3,580 

Central and South Africa 102.6 20,090 230,727 105,106 

Sub-Saharan Africa and Antarctica 64,529 26,783 124,447 71,512 

Europe 14.8 6,339 45,407 22,292 

Total World 1,293 239,159 1,376,213 724,228 

Gas – Trillion cubic feet (Tcf) 

Region Proven Undiscovered Resources 

Reserves F95 F5 Mean 

USA 183 392,600 697,600 526,900 

North America 252 413,044 1,051,199 681,399 

FSU 1,967 429,164 3,246,740 1,611,262 

Middle East and North Africa 2,565 425,371 2,607,896 1,369,933 

Asia Pacific 392 109,068 746,044 379,339 

South Asia 64 30,518 248,647 119,610 

Central and South Africa 386 96,168 1,087,521 487,190 

Sub-Saharan Africa and Antarctica 200 83,474 439,436 235,290 

Europe 187 44,706 733,412 312,365 

Total World 6,112 1,631,513 10,160,895 5,196,388 

Source: (Radler, 2005; USGS, 2000).
99

Table A.11 

 World Proved Oil Reserves (2004) 

Country 

At end 1984 

Thousand million barrels

At end 1994 

Thousand million barrels

At end 2004 

Thousand million barrels

At end 2004 

Share of total 

USA 36.1 29.6 29.4 2.5% 

Canada 9.4 10.4 16.8 1.4% 

Mexico 56.4 49.8 14.8 1.2% 

Total North America 101.9 89.8 61.0 5.1% 

Argentina 2.3 2.3 2.7 0.2% 

Brazil 2.0 5.4 11.2 0.9% 

Colombia 1.1 3.1 1.5 0.1% 

Ecuador 1.1 3.5 5.1 0.4% 

Peru 0.7 0.8 0.9 0.1% 

Trinidad & Tobago 0.6 0.6 1.0 0.1% 

Venezuela 28.0 64.9 77.2 6.5% 

Other S. & Cent. America 0.5 1.0 1.5 0.1% 

Total S. & Cent. America 36.3 81.5 101.2 8.5% 

Azerbaijan n/a n/a 7.0 0.6% 

Denmark 0.5 0.8 1.3 0.1% 

Italy 0.6 0.7 0.7 0.1% 

Kazakhstan n/a n/a 39.6 3.3% 

Norway 4.9 9.6 9.7 0.8% 

Romania 1.5 1.0 0.5 

Russian Federation n/a n/a 72.3 6.1% 

Turkmenistan n/a n/a 0.5 

United Kingdom 6.0 4.3 4.5 0.4% 

Uzbekistan n/a n/a 0.6 

Other Europe & Eurasia 83.2 63.9 2.5 0.2% 

Total Europe & Eurasia 96.7 80.3 139.2 11.7% 

Iran 58.9 94.3 132.5 11.1% 

Iraq 65.0 100.0 115.0 9.7% 

Kuwait 92.7 96.5 99.0 8.3% 

Oman 3.9 5.1 5.6 0.5% 

Qatar 4.5 3.5 15.2 1.3% 

Saudi Arabia 171.7 261.4 262.7 22.1% 

Syria 1.4 2.7 3.2 0.3% 

United Arab Emirates 32.5 98.1 97.8 8.2% 

Yemen 0.1 0.1 2.9 0.2% 

Other Middle East 0.2 0.1 0.1 

Total Middle East 430.8 661.7 733.9 61.7% 

Algeria 9.0 10.0 11.8 1.0% 

Angola 2.1 3.0 8.8 0.7% 

Chad - - 0.9 0.1% 

Rep. of Congo 0.8 1.4 1.8 0.2% 

Egypt 4.0 3.9 3.6 0.3% 

Equatorial Guinea - 0.3 1.3 0.1% 

Gabon 0.6 1.4 2.3 0.2% 

Libya 21.4 22.8 39.1 3.3% 

Nigeria 16.7 21.0 35.3 3.0% 

Sudan 0.3 0.3 6.3 0.5% 

Tunisia 1.8 0.3 0.6 0.1% 

Other Africa 1.0 0.6 0.5 

Total Africa 57.8 65.0 112.2 9.4% 

Australia 2.9 3.9 4.0 0.3% 

Brunei 1.5 1.2 1.1 0.1% 

China 16.3 16.2 17.1 1.4% 

India 3.8 5.8 5.6 0.5% 

Indonesia 9.6 5.0 4.7 0.4% 

Malaysia 2.9 5.2 4.3 0.4% 

Thailand 0.1 0.2 0.5 

Vietnam - 0.6 3.0 0.2% 

Other Asia Pacific 1.1 1.0 0.9 0.1% 

Total Asia Pacific 38.1 39.2 41.1 3.5% 

TOTAL WORLD 761.6 1017.5 1188.6 100.0% 

Of which OECD 118.7 110.6 82.9 7.0% 

 OPEC 510.0 777.4 890.3 74.9% 

 Non-OPEC £ 170.6 177.7 177.4 14.9% 

 Former Soviet Union 81.0 62.4 120.8 10.2% 

Source: (British Petroleum, 2005). 

* Over 100 years, + Less than 0.05, n/a Not available  Less than 0.05%, £ Excludes Former Soviet Union 
100

Table A.12 

 World Undiscovered Oil Resources, 2000 (Thousand Million Barrels) 

Country Onshore Offshore Total 

USA 85.9 

Canada 1.0 1.8 2.8 

Mexico 7.7 12.9 20.6 

North America 

Argentina 2.0 1.3 3.2 

Brazil * 46.7 46.7 

Colombia 5.1 - 5.1 

Ecuador 0.8 0.2 1.0 

Peru 1.8 1.5 3.3 

Trinidad & Tobago * 0.7 0.8 

Venezuela 15.6 4.1 19.7 

South & Central America 105.1 

Denmark - 0.1 0.1 

Italy 0.4 * 0.4 

Norway - 12.9 12.9 

Romania 1.1 - 1.1 

United Kingdom * 6.3 6.3 

Europe 22.3 

Azerbaijan 0.2 6.1 6.3 

Kazakhstan 7.9 13.2 21.1 

Russian Federation 66.3 11.1 77.4 

Turkmenistan 0.5 6.3 6.8 

Uzbekistan 0.1 * 0.1 

Former Soviet Union 116.0 

Iran 39.7 13.5 53.1 

Iraq 45.1 - 45.1 

Kuwait 1.6 2.2 3.8 

Oman 3.4 - 3.4 

Qatar 1.6 2.0 3.6 

Saudi Arabia 75.8 11.2 87.1 

Syria 1.3 - 1.3 

United Arab Emirates 4.4 3.3 7.7 

Yemen 3.3 * 3.3 

Middle East 229.9 

Algeria 7.7 - 7.7 

Angola 0.5 14.0 14.5 

Cameroon 0.5 1.0 1.5 

Republic of Congo 0.2 5.6 5.8 

Egypt 

Gabon 0.9 7.3 8.2 

Libya 6.6 1.7 8.3 

Nigeria 15.4 22.2 37.6 

Tunisia 1.7 0.5 2.2 

Africa 71.5 

Australia 0.2 4.8 5.0 

Brunei 0.1 1.7 1.8 

China 10.4 1.8 12.1 

India 0.8 1.8 2.6 

Indonesia 2.2 5.2 7.4 

Malaysia 0.1 3.0 3.0 

Thailand - 0.1 0.1 

Vietnam - * * 

Asia Pacific 32.4 

TOTAL WORLD 724.2 

Source: (USGS, 2000). Note: ‡Excludes Former Soviet Union, *Less than 0.05%, n/a: Not available. 
101

Table A.13 

 World Proved Natural Gas Reserves (2004) 

Country At end 1984 

Trillion cubic meters

At end 1994 

 Trillion cubic meters

At end 2004 

Trillion cubic meters

At end 2001 

Share of total 

USA 5.53 4.59 5.29 2.9% 

Canada 2.81 1.90 1.60 0.9% 

Mexico 2.17 1.94 0.42 0.2% 

Total North America 10.51 8.42 7.32 4.1% 

Argentina 0.67 0.54 0.61 0.3% 

Bolivia 0.13 0.11 0.89 0.5% 

Brazil 0.08 0.15 0.33 0.2% 

Colombia 0.11 0.21 0.11 0.1% 

Peru + 0.34 0.25 0.1% 

Trinidad & Tobago 0.31 0.29 0.53 0.3% 

Venezuela 1.67 3.97 4.22 2.4% 

Other S. & Cent. America 0.24 0.23 0.17 0.1% 

Total S. & Cent. America 3.23 5.83 7.10 4.0% 

Azerbaijan n/a n/a 1.37 0.8% 

Denmark 0.10 0.12 0.09 

Germany 0.31 0.22 0.20 0.1% 

Italy 0.25 0.30 0.17 0.1% 

Kazakhstan n/a n/a 3.00 1.7% 

Netherlands 1.90 1.85 1.49 0.8% 

Norway 0.56 1.73 2.39 1.3% 

Poland 0.09 0.16 0.12 0.1% 

Romania 0.21 0.43 0.30 0.2% 

Russian Federation n/a n/a 48.00 26.7% 

Turkmenistan n/a n/a 2.90 1.6% 

Ukraine n/a n/a 1.11 0.6% 

United Kingdom 0.73 0.66 0.59 0.3% 

Uzbekistan n/a n/a 1.86 1.0% 

Other Europe & Eurasia 37.87 58.41 0.45 0.2% 

Total Europe & Eurasia 42.02 63.87 64.02 35.7% 

Bahrain 0.21 0.15 0.09 0.1% 

Iran 14.02 20.76 27.50 15.3% 

Iraq 0.82 3.12 3.17 1.8% 

Kuwait 1.04 1.50 1.57 0.9% 

Oman 0.22 0.26 1.00 0.6% 

Qatar 4.28 7.07 25.78 14.4% 

Saudi Arabia 3.61 5.26 6.75 3.8% 

Syria 0.10 0.24 0.37 0.2% 

United Arab Emirates 3.11 6.78 6.06 3.4% 

Yemen - 0.43 0.48 0.3% 

Other Middle East + + 0.05 

Total Middle East 27.40 45.56 72.83 40.6% 

Algeria 3.44 2.96 4.55 2.5% 

Egypt 0.24 0.63 1.85 1.0% 

Libya 0.63 1.31 1.49 0.8% 

Nigeria 1.36 3.45 5.00 2.8% 

Other Africa 0.56 0.78 1.18 0.7% 

Total Africa 6.22 9.13 14.06 7.8% 

Australia 0.75 1.30 2.46 1.4% 

Bangladesh 0.35 0.30 0.44 0.2% 

Brunei 0.24 0.40 0.34 0.2% 

China 0.89 1.67 2.23 1.2% 

India 0.48 0.70 0.92 0.5% 

Indonesia 1.70 1.82 2.56 1.4% 

Malaysia 1.39 1.93 2.46 1.4% 

Myanmar 0.26 0.27 0.53 0.3% 

Pakistan 0.52 0.59 0.80 0.4% 

Papua New Guinea - 0.43 0.43 0.2% 

Thailand 0.21 0.18 0.43 0.2% 

Vietnam - 0.13 0.24 0.1% 

Other Asia Pacific 0.23 0.35 0.38 0.2% 

Total Asia Pacific 7.02 10.07 14.21 7.9% 

TOTAL WORLD 96.39 142.89 179.53 100.0% 

Of which: European Union 25 3.62 3.44 2.75 1.5% 

 OECD 15.62 15.00 15.02 8.4% 

 Former Soviet Union 37.50 58.15 58.51 32.6% 

Source: (British Petroleum, 2005). + Less than 0.05,  Less than 0.05%, n/a: Not available. 
102

Table A.14 

 World Undiscovered Natural Gas Resources, 2000 (Trillion cubic feet)

Country Onshore Offshore Total 

USA 419.9 

Canada 15.6 8.9 24.5 

Mexico 20.5 28.7 49.3 

Total North America 

Argentina 21.8 14.9 36.7 

Brazil 0.2 194.2 192.4 

Colombia 10.1 - 10.1 

Ecuador 0.3 0.2 0.6 

Peru 1.9 4.4 6.3 

Trinidad & Tobago 1.1 30.7 31.8 

Venezuela 60.3 41.0 101.2 

Total S. & Cent. America 487.2 

Denmark - 0.8 0.8 

Italy 13.0 14.3 27.3 

Norway - 183.0 183.0 

Romania 5.4 - 5.4 

United Kingdom * 23.3 23.4 

Total Europe 312.4 

Azerbaijan 1.6 65.9 67.4 

Kazakhstan 38.6 33.7 72.3 

Russian Federation 398.0 770.8 1,168.7 

Turkmenistan 142.4 65.3 207.7 

Uzbekistan 12.8 2.3 15.0 

Total Former Soviet Union 1,611.3 

Iran 176.2 138.4 314.6 

Iraq 120.0 - 120.0 

Kuwait 2.8 3.1 5.9 

Oman 32.4 1.3 33.7 

Qatar 17.5 23.6 41.1 

Saudi Arabia 625.1 55.9 681.0 

Syria 5.1 - 5.1 

United Arab Emirates 28.5 16.0 44.5 

Yemen 21.4 0.5 21.9 

Total Middle East 1,370.0 

Algeria 46.5 2.5 49.0 

Angola 1.4 41.3 42.7 

Cameroon 1.8 3.8 5.6 

Republic of Congo 0.5 16.9 17.4 

Egypt 

Gabon 2.8 21.5 24.3 

Libya 12.8 8.3 21.1 

Nigeria 55.1 68.1 123.2 

Tunisia 4.9 2.3 7.1 

Total Africa 235.3 

Australia 3.4 106.0 109.4 

Brunei 0.4 12.0 12.4 

China 82.1 3.6 85.8 

India 13.1 17.2 30.3 

Indonesia 43.4 64.3 107.7 

Malaysia 0.4 49.7 50.2 

Papua New Guinea 

Thailand - 4.7 4.7 

Vietnam - 0.8 0.8 

Total Asia Pacific 498.9 

TOTAL WORLD 5,196.4 

Source: (USGS, 2000). Note: ‡Excludes Former Soviet Union, *Less than 0.05%, n/a: Not available. 
103

Table A.15 

Bitumen (Tar Sands) and Heavy Oil Technically Recoverable Resources (2003) 

Region Bitumen (Bbbl) Heavy Oil (Bbbl) 

Western Hemisphere 531.0 310.0 

North America 530.9 35.3 

South America 0.1 265.7 

Eastern Hemisphere 119.7 133.3 

Africa 43.0 7.2 

Europe 0.2 4.9 

Middle East 0 78.2 

Asia 42.8 29.6 

Russia 33.7 13.4 

World Total 650.7 434.3 

 Source: (USGS, 2000).
104

Table A.16 

 Oil Production and Consumption Among Primary Producing Countries (2004) 

Country Production 

(1,000 barrels daily)

Consumption 

(1,000 barrels daily)

Production-Consumption 

(1,000 barrels daily)

USA 7241 20517 -13276 

Canada 3085 2206 879 

Mexico 3824 1896 1928 

Total North America 14150 24619 -10469 

Argentina 756 393 363 

Brazil 1542 1830 -288 

Colombia 551 223 328 

Ecuador 535 140 395 

Peru 93 153 -60 

Trinidad & Tobago 155 155 

Venezuela 2980 577 2403 

Other S. & Cent. America 152 1424 -1272 

Total S. & Cent. America 6764 4739 2025 

Azerbaijan 318 91 227 

Denmark 394 189 205 

Italy 104 1871 -1767 

Kazakhstan 1295 192 1103 

Norway 3188 209 2979 

Romania 119 212 -93 

Russian Federation 9285 2574 6711 

Turkmenistan 202 98 104 

United Kingdom 2029 1756 273 

Uzbekistan 152 120 32 

Other Europe & Eurasia 496 12705 -12209 

Total Europe & Eurasia 17583 20017 -2434 

Iran 4081 1551 2530 

Iraq 2027 2027 

Kuwait 2424 266 2158 

Oman 785 785 

Qatar 990 84 906 

Saudi Arabia 10584 1728 8856 

Syria 536 536 

United Arab Emirates 2667 306 2361 

Yemen 429 429 

Other Middle East 48 1354 -1306 

Total Middle East 24571 5289 19282 

Algeria 1933 242 1691 

Angola 991 991 

Cameroon 62 62 

Chad 168 168 

Rep. of Congo (Brazzaville) 240 240 

Egypt 708 566 142 

Equatorial Guinea 350 350 

Gabon 235 235 

Libya 1607 1607 

Nigeria 2508 2508 

Sudan 301 301 

Tunisia 69 69 

Other Africa 92 1839 -1747 

Total Africa 9264 2647 6617 

Australia 541 858 -317 

Brunei 211 211 

China 3490 6684 -3194 

India 819 2555 -1736 

Indonesia 1126 1150 -24 

Malaysia 912 504 408 

Thailand 218 909 -691 

Vietnam 427 427 

Other Asia Pacific 184 10786 -10602 

Total Asia Pacific 7928 23446 -15518 

TOTAL WORLD 80260 80757 -497 

Of which OECD 20732 48777 -28045 

 OPEC 32927 32927 

 Non-OPEC ‡ 35916 35916 

 Former Soviet Union 11417 3729 7688 

 Source: (British Petroleum, 2005). ‡Excludes Former Soviet Union 
105

Table A.17 

 OPEC Production Quotas (Million Barrels per Day) 

Country (OPEC Membership) 2000 2001 7/2005 (Quota) 2/2006 (Production) 

Saudi Arabia (1960) 8.26 7.58 9.10 9.40 

Iran (1960) 3.68 3.43 4.11 3.90 

Venezuela (1960) 3.03 2.57 3.22 2.50 

Iraq (1960) 2.57* 2.03* - 1.80 

UAE (1967) 2.23 2.00 2.44 2.50 

Nigeria (1971) 2.03 1.97 2.31 2.20 

Kuwait (1960) 2.10 1.87 2.25 2.60 

Libya (1962) 1.41 1.30 1.50 1.65 

Indonesia (1962) 1.27 1.10 1.45 0.92 

Algeria (1969) 0.81 0.88 0.89 1.38 

Qatar (1961) 0.67 0.66 0.73 0.80 

OPEC Total 28.06 25.39 28.00 27.85 

Footnote: Domestic use only due to U.N. embargo 

Table A.18 

 World Oil Supply Disruptions 

Date of Oil Supply Disruption 

Supply 

Duration 

(months) 

Average 

Gross 

Supply 

Shortfall 

(MBD) 

World 

Production Prior 

to Disruption 

(MBD) 

Supply 

Shortfall

(%) 

Nov. 1956-Mar. 1957 (Suez Crisis) 4 2 16.8 11.9 

Dec. 1966-Mar. 1967 (Syrian Transit Fee Dispute) 3 0.7 32.96 2.1 

Jun. 1967-Aug. 1967 (Six-Day War) 2 2 35.39 5.7 

May 1970-Jan. 1971 (Libyan Price Dispute) 8 1.3 45.89 2.8 

Oct.1973-Mar. 1974 (Arab-Israeli War) 6 4.3 57.744 7.4 

Nov. 1978-Apr. 1979 (Iranian Revolution) 6 5.6 62.906 8.9 

Oct.1980-Jan. 1981 (Iran-Iraq War) 3 4.1 58.338 7.0 

Aug. 1990-Jan. 1991 (Iraq Invasion of Kuwait) 5 4.3 60.487 7.1 

Jun. 2001-Jul. 2001 (Iraqi Oil Export Suspension) 2 2.1 67.551 3.1 

Dec. 2002-Mar. 2003(Venezuela Labor Strike) 4 2.6 68.595 3.8 

Mar. 2003-Dec. 2003 (War in Iraq) 9 2.3 69.041 3.3 

Aug. 2005-May 2006 (Hurricanes Katrina and Rita) 9 1.4 73.572 1.9 

Source: (Taylor and van Doren, 2005).
106

Table A.19 

 Sources and Uses of Cash for FRS Companies, 2003-2004 (Current Billion Dollars) 

Sources and Uses of Cash 2003 2004 

Percent 

Change 

Main Sources of Cash 

Cash Flow from Operations 105.1 135.8 29.2 

Proceeds from Long-Term Debt 26.4 18.5 -29.7 

Proceeds from Disposals of Assets 16.1 19.7 22.2 

Proceeds from Equity Security Offerings 8.4 8.1 -3.2 

Main Uses of Cash 

Additions to Investment in Place 80.0 86.5 8.2 

Reductions in Long-Term Debt 26.2 18.4 -29.8 

Dividends to Shareholders 42.8 36.5 -14.6 

Purchase of Treasury Stock 6.1 14.0 131.2 

Other Investment and Financing Activities, Net 7.9 -5.5 -169.5 

Net Change in Cash and Cash Equivalents 8.8 21.2 140.7 

Source: (EIA, 2004). 
107

Table A.20 

 Exploration and Development Expenditures by Region for FRS Companies, 1998-2004 (Current M

Total E&P Expenditures 1998 1999 2000 2001 2002 2003 U.S. Onshore 13,460 6,570 27,089 24,244 22,330 14,743 U.S. Offshroe 10,968 6,917 20,955 9,614 9,482 12,453 

Total United States 24,428 13,487 48,044 33,858 31,812 27,196 

Canada 4,806 2,056 4,881 15,324 6,687 4,903 OECD Europe 8,586 4,137 7,520 5,373 9,794 5,730 Former Soviet Union and E. Europe 1,267 606 893 881 1,273 2,120 Africa 3,134 3,094 2,719 5,547 6,091 9,187 Middle East 942 393 550 739 774 976 Other Eastern Hemisphere 3,949 3,442 6,787 4,991 6,195 4,161 Other Western Hemisphere 3,709 3,790 5,448 3,090 1,558 1,131 

Total Foreign 26,393 17,518 28,798 35,944 31,372 28,208 

World Total 50,821 31,005 76,842 69,802 63,184 55,404 

 Source: (EIA, 2004). 
108

Table A.21 

Representative Global Upstream Oil and Gas Investment Comparison 

Year O&GJa Arthur Anderson Lehmanb Chase/Salomonc 

1995 55.9 54.5 84 69 

1996 63.0 48.9 97 88 

1997 75.0 89.6 115 67 

1998 74.2 89.0 114 82 

1999 78.4 95.7 90 92 

2000 85.4 124.1 108 115 

2001 106.9 127 110 

2002 117 121 

 Note: a) (Beck, 2004). 

 b) (IEA, 2003). 

c) (Lynch, 2003). 
109

Table A.22 

U.S. Capital Spending, 1994-2003 (Current Million Dollars) 

 1994 1995 1996 1997 1998 1999 2000 2001 Drilling-Exploration 12,036 12,842 17,098 22,725 22,835 18,312 24,340 39,927 Production 2,365 2,519 3,354 4,458 4.349 3,479 4,625 7,586 OCS Lease Bonus 331 414 878 1,411 1,320 249 442 1,004  Subtotal 14,732 15,775 21,330 28,594 28,504 22,040 29,407 48,517 Refining 5,082 4,903 3,932 3,102 3,486 3,525 4,142 3,930 Petrochemicals 2,245 3,347 3,341 2,763 2,871 2,007 870 917 Marketing 2,473 2,545 2,913 2,960 3,024 2,613 2,867 3,300 Crude & Products Pipelines 778 768 632 851 1,228 1,058 201 570 Natural Gas Pipelines 1,352 1,527 1,120 1,704 1,928 1,824 3,261 3,008 Other Transportation 730 602 657 722 750 681 682 706 Mining & Other Energy 714 758 665 884 902 601 556 550 Miscellaneous 2,223 2,256 2,310 2,545 2,564 2,196 2,241 3,900  Subtotal 15,597 16,706 15,570 15,531 16,753 14,505 14,820 16,881 Total 30,329 32,481 36,900 44,125 45,257 36,545 44,227 65,398 

 Source: (Beck, 2004). 
110

Table A.23 

 Worldwide Petroleum Industry Capital Spending, 1990-2001 (Current Million Dollar

Regions and Sectors 1990 1991 1992 1993 1994 1995 1996 1997 1998 199US and Canada Crude Oil & Natural Gas 22,048 23,424 17,003 21,504 23,940 24,616 30,140 36,674 39,075 41,89Refineries 4,930 6,831 6,933 6,031 5,678 5,472 4,382 3,411 3,834 4,16 Subtotal 26,978 30,355 23,936 27,535 29,618 30,088 34,522 40,085 42,909 46,05Mexico, C. and S. America Crude Oil & Natural Gas 6,220 7,605 6,254 5,637 7,362 9,130 9,290 10,938 9,573 10,04Refineries 1,864 1,848 1,872 1,938 1,955 2,057 2,080 2,130 2,106 2,35 Subtotal 8,084 9,453 8,126 7,575 9,317 11,187 11,370 13,068 11,679 12,40Western Europe Crude Oil & Natural Gas 14,770 16,829 12,276 11,361 12,290 13,667 14,850 16,220 14,380 14,78Refineries 3,050 3,083 3,061 3,110 3,119 3,186 3,252 3,297 3,320 3,60 Subtotal 17,820 19,912 15,337 14,471 15,409 16,853 18,102 19,517 17,700 18,38Middle East and Africa Crude Oil & Natural Gas 3,957 4,002 4,017 4,403 4,191 4,570 4,876 6,588 6,683 7,07Refineries 1,340 1,277 1,311 1,372 1,432 1,519 1,571 1,610 1,637 1,80 Subtotal 5,297 5,229 5,328 5,775 5,623 6,089 6,447 7,198 8,320 8,88Far East and Australasia Crude Oil & Natural Gas 4,436 4,695 3,922 4,194 4,156 3,893 3,799 4,605 4,459 4,58Refineries 2,498 2,611 2,759 2,936 3,052 3,385 3,642 3,735 3,781 4,17 Subtotal 6,934 7,306 6,681 7,130 7,208 7,278 7,441 8,340 8,240 8,75World Totals Crude Oil & Natural Gas 51,431 56,555 43,472 47,099 51,939 55,876 62,955 75,025 74,170 78,37Refineries 13,682 15,600 15,936 15,387 15,236 15,619 14,927 14,183 14,678 16,10 Total World 65,113 72,155 59,408 62,486 67,175 71,495 77,882 89,208 88,848 94,48

 Source: (Beck, 2004).
111

Table A.24 

Lifting Costs by Region for FRS Companies, 2003-2004 

(2004 Dollars Per Barrel of Oil Equivalent) 

Direct Lifting Costs Production Taxes Total 

Region 2003 2004 2003 2004 2003 2004 

United States 

Onshore -- -- -- -- 5.66 6.08 

Offshore -- -- -- -- 3.34 4.25 

 Total United States 3.77 4.19 1.13 1.32 4.90 5.52 

Foreign 

Canada 5.34 5.15 0.23 0.23 5.56 5.38 

OECD Europe 4.39 4.54 0.84 0.70 5.23 5.24 

FSU/E. Europe 4.43 5.74 0.75 1.24 5.18 6.98 

Africa 

Middle East 

Other E. Hemisphere 

Other W. Hemisphere 

 Total Foreign 

3.89 

3.99 

2.97 

2.14 

3.96 

4.06 

4.36 

4.26 

1.88 

4.25 

1.32 

0.15 

1.09 

1.45 

0.88 

1.51 

0.19 

1.53 

1.72 

1.01 

5.20 

4.14 

4.06 

3.59 

4.84 

5.57 

4.56 

5.79 

3.60 

5.27 

Worldwide Total 3.87 4.23 1.00 1.16 4.87 5.39 

Source: (EIA, 2004). 

Table A.25 

 Finding Costs by Region for FRS Companies, 2001-2003 and 2002-2004 

(2004 Dollars Per Barrel of Oil Equivalent) 

Region 2001-2003 2002-2004 Change (%) 

United States 

Onshore 9.16 7.18 -21.6 

Offshore 10.24 27.66 170.0 

 Total United States 9.56 10.33 8.1 

Foreign 

Canada 12.26 26.09 112.8 

OECD Europe 9.86 12.16 23.3 

Former Soviet Union and Eastern Europe 2.63 4.30 63.8 

Africa 

Middle East 

Other Eastern Hemisphere 

Other Western Hemisphere 

 Total Foreign 

5.79 

4.05 

4.05 

3.98 

5.87 

7.55 

6.76 

6.18 

4.98 

8.30 

30.4 

67.1 

52.5 

25.0 

41.3 

Worldwide Total 7.28 9.18 26.2 

Source: (EIA, 2004). 
112

Table A.26 

 The Prospectivity of a Region Is Influenced by Many Factors 

Categorization Potential Factors 

Geologic Proved Reserves 

Production 

Reserves Addition 

Undiscovered Resources 

Technical F&D Cost 

Number of IOCs 

Years of Production 

Past Peak Production 

Maturity Status 

Frontier Acreage 

Infrastructure Availability 

Country GDP 

GDP per Capita 

Oil Revenue Volatility 

Import/Export Status 

Economic System 

FDI 

Macroeconomic Stability 

Negotiation Experience 

Company Type 

Regional Influences 

Corruption Index 

Geopolitical Political Risk 

OPEC Membership 

Political Agenda 

Political Systems 

Legal Rule of Law 
113

Table A.27 

 Hydrocarbon Net Exporting Countries Oil and Natural Gas Exports and Fiscal 

Revenues in 2003 

Oil and Gas Exports as a percent Country’s fiscal oil and gas as share 

Country of world oil and gas exports of country’s GDP of country’s GDP

Saudi Arabia 13.5 38.3 28.1 

Russian Federation 11.8 17.0 6.0 

Norway 6.5 18.4 12.2 

United Arab Emirates 4.7 36.8 35.8 

Iran 4.3 19.8 16.3 

Nigeria 4.3 46.1 28.0 

Algeria 3.9 36.2 26.4 

United Kingdom 3.8 1.3 0.4 

Netherlands 3.4 4.0 n/a 

Venezuela 3.3 24.6 23.0 

Kuwait 3.0 44.8 48.1 

Mexico 3.0 3.0 7.9 

Indonesia 2.4 6.3 4.5 

Canada 2.4 1.7 0.2 

Libya 1.9 47.6 40.5 

Iraq 1.6 38.4 n/a 

Qatar 1.5 47.0 24.9 

Oman 1.5 43.1 35.4 

Angola 1.4 65.3 28.3 

Malaysia 1.2 7.4 4.3 

Kazakhstan 1.1 23.6 6.2 

Argentina 0.9 4.3 1.7 

Bahrain 0.8 53.9 24.4 

Syria 0.7 19.3 14.4 

Brunei Darussalam 0.6 80.0 29.1 

Denmark 0.6 1.8 0.7 

Vietnam 0.6 9.8 5.3 

Trinidad & Tobago 0.6 34.4 11.5 

Yemen 0.5 30.5 23.6 

Colombia 0.5 4.4 2.9 

Egypt 0.5 3.9 0.8 

Turkmenistan 0.5 26.6 9.3 

Equatorial Guinea 0.5 96.6 23.7 

Ecuador 0.4 9.7 13.2 

Azerbaijan 0.4 31.5 15.2 

Congo 0.3 59.1 20.4 

Sudan 0.3 12.3 9.5 

Gabon 0.2 42.6 16.2 

Cameroon 0.2 7.6 4.5 

Cote d’Ivoire 0.1 4.9 1.3 

Bolivia 0.1 6.1 4.6 

Papua New Guinea 0.1 13.0 4.6 

Uzbekistan 0.1 3.8 5.2 

Chad 0.1 8.3 0.5 

Total: 44 Countries 90.1 

Source: (IMF, 2004).
114

Table A.28 

 One Factor, Two Dimensional Contract Classification 

Development Status Contract Type 

Industrial 

Developing 

JV 

JV, PSC 

Note: JV=Joint Venture, PSC=Production Sharing Contract. 

Table A.29 

 One Factor, Five Dimensional Contract Classification 

Political System Example Country 

Mature Democracy 

Factional Democracy 

Paternalistic Democracy 

Predatory Democracy 

Reformist Democracy 

US, UK, Canada, Norway 

Ecuador, Venezuela, Columbia 

Saudi Arabia, Kuwait, Gulf States 

Nigeria 

Indonesia 

Table A.30 

 Multi-Dimensional Contract Classification 

Country/Region Subcategory Example Country 

Industrialized 

OPEC 

FSU 

SouthEast Asia 

Africa 

Laissez Faire 

Dirigiste 

Rich 

Less Rich 

High Prospectivity 

Modest Prospectivity 

Low Prospectivity 

High Prospectivity 

Modest Prospectivity 

Low Prospectivity 

High Prospectivity 

Modest Prospectivity 

Low Prospectivity 

US, UK, Spain, Canada, Australia, Sweden, 

Denmark, Finland, Switzerland, Argentine, 

Chile 

France, Germany, Norway, Japan, Italy, Austria, 

Portugal, Greece 

Saudi Arabia, Kuwait, UAE, Libya, Qatar, 

Oman, Iran, Iraq 

Algeria, Venezuela, Indonesia, Nigeria 

Russia, Kazakhstan, Uzebekistan, Turkmenistan 

Azerbaijan, Tajikistan, Kyrgistan 

Ukraine, Belarus 

Malaysia 

Thailand, China 

Korea, Taiwan 

Angola, Egypt, Libya, Nigeria 

Chad, Sudan, Niger 

Gabon, Senegal, Morocco 
115

Table A.31 

 Two Factor, Four Dimensional Contract Classification 

Economic Strength Importer Exporter 

Weak PSC 

RC 

JV 

PSC 

Strong JV 

PSC 

PSC 

SC 

 Note: JV = Joint Venture, PSC = Production Sharing Contract, RC = Risk Contract, 

SC = Service Contract. 
116

Table A.32 

 Representative Contract Terms and Government Take 

Country Contract Typea Government Takeb Star Systemc 

USA R/T Deepwater: (38, 42) 

Shelf : (48,51) 

Deepwater: 4 

Shelf: 3 

Mexico SC (30, 32) 

North America 

Argentina R/T (47, 49) 5 

Colombia R/T (79, 82) 1 

Ecuador PSA (58, 60) 3 

Peru PSA, R/T (58, 62) 5 

Trinidad & Tobago PSA Offshore: (48, 50) 

Onshore: (62,66) 

Offshore: 4 

Onshore: 3 

Venezuela SC (88, 93) 1 

South & Central 

America 

 

Italy 5 

Norway 2 

United Kingdom 5 

Europe 

Kazakhstan PSA, 

ROR 

(83, 88) 

Russian Federation 1 

Former Soviet Union 

Syria PSA (83, 87) 1 

Yemen PSA (72, 79) 2 

Middle East 

Angola PSA (81, 88) 

Republic of Congo R/T (67, 69) 

Egypt PSA (79, 82) 

(85, 90) 

Offshore: 3 

Onshore: 1 

Gabon PSA (69, 76) 1 

Nigeria 1 

Tunisia PSA, R/T (79, 85) 

Africa 

Australia R/T Off: (53, 56) 

On: (63, 66) 

Offshore: 4 

Onshore: 3 

Brunei R/T (82, 84) 2 

China PSA (72, 77) 3 

India PSA (61, 69) 

Indonesia PSA East: (69, 71) 

West: (87, 89) 

1 

1 

Malaysia PSA Frontier: (69, 74) 

Onshore: (88, 91) 

Frontier: 3 

Onshore: 2 

Papua New Guinea R/T, ROR (67, 76) 2 

Thailand R/T (69, 74) 2 

Vietnam PSA (79, 82) 

Asia Pacific 

Footnote: (a) PSA = Production Sharing Agreement, R/T = Royalty Tax, ROR = Rate of Return Features, SC = Service Contract. 

 (b) Source: (Johnston, 1994). 

 (c) Source: (Van Meurs and Seck, 1995 and 1997). 
117

Table A.33 

The Notion of Take Changes Throughout the Life of a Prospect 

Stage Notation Characteristics 

Bid Submission τ1 Based on estimates of the field size 

distribution, expected development cost, 

production schedule, fiscal terms F, and 

work commitment W, take is evaluated 

Bid Acceptance and Award τ2 F and W are negotiated with HG to 

determine values of τ2

Commercial Discovery τ3 Field size is known and with estimates of 

development and production costs, F will 

determine τ3 subject to exogenous 

conditions

Production τ4 Field size, development costs, production 

expenses, etc. are known with a higher degree 

of certainty, and as production proceeds, these 

parameters become better defined. Take will 

vary throughout the productive life of a field 

based on the terms of F and exogenous 

conditions 

Abandonment τ5 At abandonment and with perfect information, 

a “look-back” analysis can be performed to 

determine the exact value of take as long as 

cost and revenues are known precisely and the 

terms of F are available
118

Table A.34 

 Trends in PSA Contract Terms 

 Maximum Maximum Cost Oil IOC Profit Oil Bo Royalty (%) (%) Max (%) Min (%) Signature ($M) Onshore 9+ 70+++ 53+ 30 4 Offshore 7+++ 68+ 61++ 33++ 1.3 - Exporters 10+++ 69++ 50++ 27+ 4.5+ Importers 5 69++ 60+ 38+ 1.8+ OPEC 5++ 100+++ 55++ 30+ 1.1 - - South/Central Africa 8+ 70+++ 62+ 32+ 2.5 Eastern Europe 6+++ 62+++ 58+ 38 - 0.8+++ Asia/Australia 5.5++ 76+ 55++ 28 1.8 - Central America/Caribbean 10+ 100+++ 90+++ 50+++ n/a Middle East 8.5+ 40 - 25 - - 16 6+++ 

North Africa 10+++ 85+++ 72+++ 27++ 3+++ South America 8.5+ 60+++ 45 - 30 - - n/a 

 Source: (Bindemann, 1999).  Footnote: (1) Figures represent 1997/1998 contract averages. 

 (2) + (-) slight increase (decrease); ++ (- -) increase (decrease); +++ (- - -) strong increase (decrease). 
119

0

2

4

6

8

10

12

14

16

194919541959196419691974197919841989199419992004

Year

Million Barrels per Day

Transportation

 Electric Power

 ↓

Residential and Commercial 

Industrial

Figure A.1. Estimated Petroleum Consumption by Sector, 1949-2004 (EIA, 2005). 

0

0.5

1

1.5

194919541959196419691974197919841989199419992004

Year

Million Barrels per Day

Residential Fuel Oil

Distillate Fuel Oil

Kerosene

LPG 

t ti

Figure A.2. Estimated Petroleum Consumption – Residential and Commercial 

 Sectors, 1949-2004 (EIA, 2005). 
120

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

1.8

2

1949

1954

1959

1964

1969

1974

1979

1984

1989

1994

1999

2004

Year

Million Barrels per Day

LPG

Distillate Fuel Oil

Asphalt and 

Road Oil

Figure A.3. Estimated Petroleum Product Consumption – Industrial Sector, 

 1949-2004 (EIA, 2005). 

0

1

2

3

4

5

6

7

8

9

10

194919541959196419691974197919841989199419992004

Year

Million Barrels per Day

Motor Gasoline 

Distillate Fuel Oil

Jet Fuel

Figure A.4. Estimated Petroleum Product Consumption – Transportation 

 Sector, 1949-2004 (EIA, 2005). 

 
121

0

0.5

1

1.5

2

194919541959196419691974197919841994199419992004

Year

Million Barrels per Day

Figure A.5. Estimated Petroleum Consumption – Electric Power Sector, 

 1949-2004 (EIA, 2005). 

0

5

10

15

20

25

1949

1954

1959

1964

1969

1974

1979

1984

1989

1994

1999

2004

Year

Million Barrels per Day

Net Imports

Production 

Consumption 

Figure A.6. Production, Consumption, and Net Imports of Crude Oil, 

 1949-2004 (EIA, 2005).
122

0

2

4

6

8

10

12

14

16

18

194919541959196419691974197919841989199419992004

Year

Million Barrels per Da

y

Natural Gas Plant Liquids and Other Liquids 

Crude Oil 

Figure A.7. Refinery Input, 1949-2004 (EIA, 2005). 

0

4

8

12

194919541959196419691974197919841989199419992004

Year

Million Barrels per Day

Residual Fuel Jet Fuel

Motor Gasoline

Distillate Fuel 

Figure A.8. Refinery Output, 1949-2004 (EIA, 2005).
123

Selected Events: 

1 – OPEC begins to assert power, raises tax rate and posted prices 

5 – OPEC freezes posted prices 

16 – OPEC raises prices 15% 

23 – First major fighting in Iran-Iraq war 

42 – Iraq invades Kuwait 

50 – Nigerian oil workers strike 

51 – Extreme cold weather in the US and Europe 

58 – OPEC pledges additional production cuts for the thirds time 

62 – September 11, 2001 terrorist attacks 

65 – Continued unrest in Venezuela 

69 – Hurricane Ivan hits the Gulf of Mexico 

Figure A.9. World Nominal Oil Price Chronology (EIA, 2005). 
124

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

198819901992199419961998200020022004

Year

Cents Per Gallon, Excluding Taxes

Motor Gasoline

No. 2 Distillate

Residual Fuel Oil

Crude Oil Acquisition

Figure A.10. Crude Oil Refiner Acquisition Costs and Refiner Sales Prices for 

 Selected Petroleum Products, 1988-2004 (EIA, 2005). 
125

0 2 4 6 8 10 12 14

Real estate

Communication

Primary metals

Chemicals

Machinery and computer equipment

Transport equipment

Retails

Gas downstream

Electricity

Coal mining

Oil and gas refinery and marketing

Oil and gas exploration and production

Oil and gas equipment and service

Oil and gas drilling

Integrated oil and gas 

Percent

Figure A.11. Average Return on Investment by Industry, 1993-2002 (IEA, 2003). 

0 1 2 3 4 5 6 7 8 9 10

Real estate

Communication

Primary metals

Chemicals

Machinery and computer equipment

Transport equipment

Retails

Gas downstream

Electricity

Coal mining

Oil and gas refinery and marketing

Oil and gas exploration and production

Oil and gas equipment and service

Oil and gas drilling

Integrated oil and gas 

Standard Deviation

Figure A.12. Volatility of Return on Investment by Industry, 1993-2002 

 (IEA, 2003). 
126

Figure A.13. Return on Stockholder’s Equity for FRS Companies and the S&P 

 Industrials, 1973-2004 (EIA, 2004). 

Figure A.14. Return on Net Investment for U.S. and Foreign Oil and Gas 

 Production, 1977-2004 (EIA, 2004). 
127

Figure A.15. Cash Flow from Operations and Exploration and Production 

 Expenditures for FRS Companies (EIA, 2004). 

Figure A.16. Worldwide Expenditures for Exploration, Development, and 

 Production for FRS Companies (EIA, 2004). 

 
128

Figure A.17. FRS Expenditures for Oil and Natural Gas Exploration by 

 Region, 1995-2004 (EIA, 2004). 

 
129

Figure A.18. FRS Expenditures for Oil and Natural Gas Development by Region, 

 1995-2004 (EIA, 2004). 

 

Figure A.19. Direct Oil and Gas Lifting Costs for FRS Companies, 1981-2004 

 (EIA, 2004). 

 
130

Figure A.20. U.S. Onshore, U.S. Offshore, and Foreign Three-Year WeightedAverage Finding Costs for FRS Companies, 1981-1983 to 2002-2004 

(EIA, 2004). 
The Department of the Interior Mission

As the Nation's principal conservation agency, the Department of the Interior has responsibility 

for most of our nationally owned public lands and natural resources. This includes fostering 

sound use of our land and water resources; protecting our fish, wildlife, and biological diversity; 

preserving the environmental and cultural values of our national parks and historical places; 

and providing for the enjoyment of life through outdoor recreation. The Department assesses 

our energy and mineral resources and works to ensure that their development is in the best 

interests of all our people by encouraging stewardship and citizen participation in their care. 

The Department also has a major responsibility for American Indian reservation communities 

and for people who live in island territories under U.S. administration. 

The Minerals Management Service Mission 

As a bureau of the Department of the Interior, the Minerals Management Service's (MMS) 

primary responsibilities are to manage the mineral resources located on the Nation's Outer 

Continental Shelf (OCS), collect revenue from the Federal OCS and onshore Federal and Indian 

lands, and distribute those revenues. 

Moreover, in working to meet its responsibilities, the Offshore Minerals Management Program 

administers the OCS competitive leasing program and oversees the safe and environmentally 

sound exploration and production of our Nation's offshore natural gas, oil and other mineral 

resources. The MMS Minerals Revenue Management meets its responsibilities by ensuring the 

efficient, timely and accurate collection and disbursement of revenue from mineral leasing and 

production due to Indian tribes and allottees, States and the U.S. Treasury. 

The MMS strives to fulfill its responsibilities through the general guiding principles of: (1) being 

responsive to the public's concerns and interests by maintaining a dialogue with all potentially 

affected parties and (2) carrying out its programs with an emphasis on working to enhance the 

quality of life for all Americans by lending MMS assistance and expertise to economic 

development and environmental protection.