Africa’s 

Booming Oil and Natural Gas 

Exploration and Production:

National Security Implications for 

the United States and China

Africa’s 

Booming Oil and Natural Gas 

Exploration and Production:

National Security Implications for 

the United States and China

David E. Brown

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Strategic Studies Institute

and

U.S. Army War College Press

AFRICA’S BOOMING OIL AND NATURAL GAS

EXPLORATION AND PRODUCTION:

NATIONAL SECURITY IMPLICATIONS 

FOR THE UNITED STATES AND CHINA

David E. Brown

December 2013

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Previous monographs authored by Mr. Brown and published

by SSI are:

1. Hidden Dragon, Crouching Lion: How China’s Advance in 

Africa is Underestimated and Africa’s Potential Underappreciated, 

September 2012;

2. The Challenge of Drug Trafficking to Demographic Governance 

and Human Security in West Africa, May 2013; and,

3. AFRICOM at 5 Years: The Maturation of a New U.S. 

Combatant Command, August 2013.

ISBN 1-58487-603-4
v

FOREWORD

The Strategic Studies Institute (SSI) of the U.S. 

Army War College (USAWC) has maintained close 

and positive professional ties with our colleagues 

at the Africa Center for Strategic Studies (ACSS) in 

Washington, DC, since ACSS’s founding in 1999. The 

Africa Center is the preeminent U.S. Department of 

Defense (DoD) institution for strategic security studies, research, and outreach in Africa. 

I am pleased that SSI and ACSS are once more 

able to collaborate on this publication, the fourth SSI 

monograph authored by David E. Brown during his 

tenure as Senior Diplomatic Advisor at ACSS. Mr. 

Brown brings unique economic analysis and foreign 

policy perspectives to the important topic of this 

monograph: Africa’s Booming Oil and Natural Gas Exploration and Production: National Security Implications 

for the United States and China. In September 2012, SSI 

published this author’s monograph entitled Hidden 

Dragon, Crouching Lion: How China’s Advance in Africa 

is Underestimated and Africa’s Potential Underappreciated. In that monograph, the focus was on China’s 

advance in Africa, while Africa’s development was a 

sub-theme. This monograph reverses this emphasis, 

with the primary focus being Africa, specifically its 

oil and natural gas exploration and production, while 

China is a sub-theme, specifically the investment of 

its national oil companies (NOCs) in Africa and the 

implications of African energy developments for 

Beijing’s national security and military strategy. Importantly, this present monograph is also different in 

that it includes a discussion of U.S. energy firms in Africa and the importance of the continent to America’s 

energy security and national interests. 
This monograph on Africa’s energy future describes how the frenetic search for hydrocarbons in 

Africa has become so intense and wide ranging that 

there is planned or ongoing oil and gas exploration in 

at least 51 of the continent’s 54 countries. Knowledge 

about Africa’s geology is improving rapidly, generating great optimism about Africa’s future growth and 

strategic position in the global economy. Because of 

a domestic boom in shale oil and gas in the United 

States, however, our nation’s energy imports from Africa have been falling rapidly in recent years, raising 

the key strategic issue of whether Africa matters as 

much to U.S. energy security as it once did. Around 

2030, North America is forecast to become a net oil 

exporter and will have little dependence on Africa for 

its energy needs. As Mr. Brown points out, the answer 

may be that, while Africa may be becoming less important for U.S. energy security, it is becoming more 

important for broader U.S. national security. He shows 

how this is so for a variety of reasons, such as the extraordinary trade and investment opportunities that 

this rapidly growing continent represents, including 

the need for $2.1 trillion in oil and gas sector investments between now and 2035 to realize its potential. 

Already, U.S. investments in African oil and gas in at 

least 22 countries on the continent are enormous, with 

prospects for future rapid growth. 

At the same time, the United States is also an exception. As this monograph explains, for most major consuming regions, notably our Western allies and China, 

Africa has already become a crucial element in their 

energy diversification strategies. Africa is playing an 

increasing—not decreasing—role for them as an energy supplier. Africa’s importance for Beijing’s energy 

security continues to rise because China, despite shale 

vi
vii

discoveries of its own, will increasingly depend on energy imports until well past 2040. Examining also China’s military white paper, Mr. Brown makes the key 

strategic prediction that, as superpower rivals in the 

21st century, Washington’s increasing energy security 

will make Beijing’s own increasing energy insecurity 

be felt even more acutely, pushing the People’s Liberation Army to accelerate adoption of a “two ocean” 

military strategy that includes an enduring presence 

in the Indian Ocean as well as in the Pacific Ocean. 

At the end of this monograph, taking up almost 

two-thirds of its length, is an appendix with a series 

of country profiles on oil and gas exploration and production in 51 of 54 African nations and the disputed 

territory of the Western Sahara. The profiles focus on 

U.S. and Chinese energy companies, but also discuss 

those from other developed and emerging nations.

SSI is pleased to offer this monograph to assist U.S. 

Army and DoD senior leaders and strategic thinkers in 

understanding the key issues of the day.

 

 DOUGLAS C. LOVELACE, JR.

 Director

 Strategic Studies Institute and

 U.S. Army War College Press

ix

ABOUT THE AUTHOR

DAVID E. BROWN is a career member of the Senior 

Foreign Service, who joined the Africa Center for 

Strategic Studies (ACSS) as Senior Diplomatic Advisor in August 2011. His prior African experience includes serving as the Senior Advisor to the J-5 (Strategy, Plans, and Programs) Director of the U.S. Africa 

Command (AFRICOM) in Stuttgart, Germany; three 

times as Deputy Chief of Mission at U.S. Embassies in 

Cotonou, Benin; Nouakchott, Mauritania; and Ouagadougou, Burkina Faso; and as Economic Officer at the 

U.S. Consulate-General in Lubumbashi, Democratic 

Republic of the Congo. Mr. Brown’s non-Africa overseas tours have been as Consul General in Chengdu, 

China; and Economic Officer in Beijing; Tokyo, Japan; 

and Moscow, Russia. He has also served in Washington, DC, as the Director of the Office of Environmental 

Policy; as Economic Officer in the Bureau of Economic

and Business Affairs responsible for trade policy with 

developing countries, including Africa; and on the

Canada desk, with responsibilities for economic, consular, and law enforcement issues. Prior to joining the 

U.S. Department of State, he worked in Miami as the 

business manager of the Latin American Bureau of CBS 

News. Mr. Brown holds a B.A. in government (political science) from Cornell University; an MBA from the 

University of Chicago, specializing in finance; and an 

MBA from the University of Louvain, Belgium, with

majors in econometrics and international business.

xi

SUMMARY

The frenetic search for hydrocarbons in Africa 

has become so intense and wide ranging that there is 

planned or ongoing oil and gas exploration in at least 

51 of the continent’s 54 countries. Knowledge about 

Africa’s geology is improving rapidly, generating 

great optimism about the continent’s energy future. 

Onshore and offshore rifts and basins created when 

the African continent separated from the Americas 

and Eurasia 150 million years ago are now recognized 

as some of the most promising hydrocarbon provinces 

in the world. Offshore Angola and Brazil, Namibia 

and Brazil, Ghana and French Guyana, Morocco and 

Mexico, Somalia and Yemen, and Mozambique and 

Madagascar are just a few of the geological analogues 

where large oil fields have been discovered or are believed to lie. One optimistic but quite credible scenario 

is that future discoveries in Africa will be around five 

times their current level based on what remains unexplored on the continent versus currently known 

sub-soil assets. If proven true, this could have a profoundly positive impact on Africa’s future growth and 

strategic position in the global economy. 

Africa had proven oil reserves of 132.4 billion barrels at the end of 2011, an increase of 154 percent over 

the 1980 figure of 53.4 billion barrels. Because of definitional issues of what constitutes “proven reserves,” 

however, this figure likely grossly underestimates Africa’s oil and gas potential and does not include likely 

future reserves in the Mauritania Basin in the country 

of the same name (discovered in 2001); the Albertine 

Basin in Uganda, which straddles the Democratic Republic of the Condo (DRC) and the Kenyan part of the 

East African Rift (2006 for Uganda, 2012 for Kenya); 
xii

the Tano Basin in Ghana (2007); the Rovuma Basin in 

Mozambique and Tanzania (2010 in both countries); 

and the Sierra Leone/Liberia Basin in both countries 

(2010 for Sierra Leone, 2012 for Liberia). Moreover, 

no unconventional reserves have been added to these 

“proven reserve” estimates despite the fact that the 

continent has substantial, proven heavy oil/bitumen 

in several countries including Congo (Brazzaville), 

Nigeria, and Madagascar, and potential shale gas, 

most notably in South Africa, Algeria, Libya, Tunisia, 

and Ethiopia. 

Africa has already become a crucial element in the 

energy diversification strategies being adopted in major consuming regions, notably China, and offers relative freedom for international oil companies (IOCs) to 

invest and operate. Africa will be the world’s fourth 

most important region for oil production from 2010 to 

2035, after the Middle East and Europe/Eurasia, not 

far behind North America, and ahead of Latin America 

and East Asia/Australia. Africa is also starting to play 

a more prominent role in international markets for 

natural gas, which is currently characterized by disparate regional markets but is slowly moving toward 

a more interconnected, global gas market. One reason 

for this is the Panama Canal expansion, which will 

allow much larger PANAMAX LNG tankers to unite 

the Atlantic Basin and the Pacific Basin—much as the 

advent of oil supertankers fostered a global market in 

oil. Africa’s total natural gas production will increase 

rapidly over the next 2 decades, from 188.1 million 

tons of oil equivalent (TOE) in 2010 to 257.2 million 

TOE in 2020 and 356.8 million TOE in 2030. 

Because of a domestic boom in shale oil and gas in 

the United States, our nation’s energy imports from 

Africa have been falling rapidly in recent years, rais-
xiii

ing the key strategic issue of whether Africa matters 

as much to U.S. energy security as it once did. Around 

2030, North America is forecast to become a net oil exporter—an outcome that also means the United States 

will enjoy an order of magnitude greater energy security in 20 years than it does at present, and will have 

little dependence on Africa for its energy needs. The 

answer may be that, while Africa may be becoming 

less important for U.S. energy security, it is becoming more important for broader U.S. national security. This is so for a variety of reasons, such as the extraordinary trade and investment opportunities that 

this rapidly growing continent represents, including 

the need for $2.1 trillion in oil and gas sector investments between now and 2035 to realize its potential. 

Already, U.S. investments in African oil and gas in at 

least 22 countries on the continent are enormous, with 

prospects for future rapid growth. 

Africa is also playing an increasing—not decreasing—role as an energy supplier to our Western allies 

and China. Africa’s natural resources, above all oil and 

gas, are already China’s top national security interest 

in the continent and will remain so in the coming decades. In December 2012, China overtook the United 

States as the world’s largest oil importer. Africa’s importance for Beijing’s energy security continues to rise 

because China, despite shale discoveries of its own, 

will increasingly depend on energy imports until well 

past 2040. As superpower rivals in the 21st century, 

Washington’s increasing energy security will make 

Beijing’s own increasing energy insecurity be felt even 

more acutely, pushing the People’s Liberation Army 

to accelerate adoption of a “two ocean” military strategy that includes an enduring presence in the Indian 

Ocean as well as the Pacific Ocean. 
xiv

Up to now, China’s “oil diplomacy” in Africa has 

been most successful in niche markets such as Angola 

(due to corruption and to its $14 billion in infrastructure-for-oil deals), and in other African countries, 

such as Sudan and Niger, with fields that have been 

ignored as politically sensitive or too marginal by 

major Western companies. Chinese oil companies are 

rapidly increasing their energy investments in several 

other African nations, however, and already have a 

significant presence in three major oil and gas producing countries—Algeria, Angola, and Nigeria—and in 

four smaller producers—Cameroon, Chad, Gabon, 

and Sudan.

At the end of this monograph, taking up almost 

two-thirds of its length, is an appendix with a series 

of country profiles on oil and gas exploration and production in 51 of 54 African nations and the disputed 

territory of the Western Sahara. The profiles focus on 

U.S. and Chinese energy companies and discuss those 

from other developed and emerging nations.
xv

GLOSSARY

bbbl billion barrels of oil

bbl oil barrel

bcf/d billion cubic feet per day

bcf/y billion cubic feet per year

bcm billion cubic meters

BOE barrels of oil equivalent

BOE/D barrels of oil equivalent per day

bn billion

bpd barrels per day

btu British thermal unit

cf/d cubic feet per day

EEZ Exclusive Economic Zone

EIA U.S. Energy Information

Administration

EITI Extractive Industries Transparency

Initiative

EOR enhanced oil recovery

E&P exploration and production

GIP gas in place

IEA International Energy Agency

IOC International oil company

JDZ Joint Development Zone

LNG liquefied natural gas

mmscf/d million standard cubic feet per day

mmt/y million metric tons per year

mt/y metric tons per year

mpta million tons per annum

m3/d cubic meters per day

NOC National Oil Company

OECD Organisation for Economic

Co-operation and Development

OOIP original oil in place

OPEC Organization of Petroleum

Exporting Countries
PSA Production Sharing Agreement

PSC Production Sharing Contract

TOE tons of oil equivalent

tcf trillion cubic feet

tcm trillion cubic meters

UN United Nations

USGS United States Geological Survey

xvi
1

AFRICA’S BOOMING OIL AND NATURAL GAS

EXPLORATION AND PRODUCTION:

NATIONAL SECURITY IMPLICATIONS 

FOR THE UNITED STATES AND CHINA

INTRODUCTION 

In September 2012, the Strategic Studies Institute 

(SSI) of the U.S. Army War College (USAWC) published this author’s monograph entitled Hidden Dragon, Crouching Lion: How China’s Advance in Africa is Underestimated and Africa’s Potential Underappreciated. In 

that monograph, the focus was on China’s advance in 

Africa, while Africa’s development was a sub-theme. 

This monograph reverses this emphasis, with the primary focus being Africa, specifically its oil and natural 

gas exploration and production (E&P), while China is 

a sub-theme, specifically the investment of its national 

oil companies (NOCs) in Africa and the implications 

of African energy developments for Beijing’s national 

security and military strategy. Importantly, this present monograph is also different in that it includes a 

discussion of U.S. energy firms in Africa and the importance of the continent to America’s energy security 

and national interests. 

Reasons for Optimism about Africa Oil and Gas 

Potential. 

About 75 percent of the undiscovered technically 

recoverable oil outside of the United States is in four 

other areas of the globe: Africa, the Middle East, South 

America and the Caribbean, and the Arctic provinces 

of North America.1

 The author has intentionally listed 

Africa first among these regions—even ahead of the 
2

Middle East—because its enormous long-term potential is significantly underestimated in conventional 

analyses, which do not look beyond 2040.2 Why such 

optimism about Africa’s long-term leadership role in 

the global energy market? 

First, the research for this paper, based on over 

1,000 source documents, revealed an extraordinary 

picture of momentous changes in Africa, both in 

understanding of the continent’s geology and of the 

frenetic pace of ongoing oil and gas exploration. The 

hunt for hydrocarbons in Africa has become so intense 

and wide ranging that the author could find no evidence of planned or ongoing oil and gas exploration 

in only three of the continent’s 54 countries: Burkina 

Faso, a smaller country in inland West Africa; and 

Lesotho and Swaziland, two small nations that are, 

respectively, wholly or partially surrounded by the 

Republic of South Africa. With few exceptions—such 

as established producers Algeria and Nigeria, where 

short-sighted government policies have discouraged 

Western oil producers from expanding investment—

Africa has been the site of a veritable exploration 

boom. In country after country, one reads of how a 

well has been drilled for the first time in “X” number 

of years, sometimes well over 20 years. Even the continent’s “ultra-frontier” countries are being explored. 

Just one example is the extensive, ongoing exploration 

efforts in troubled Somalia—a country whose central 

government dissolved into chaos in 1991 and is still 

plagued by terrorist group Al Shabaab. This exploration boom in Africa has already led to a series of new oil 

and gas fields and is laying the foundation for future 

large discoveries. The 2007 discovery of oil in Ghana 

in West Africa, for example, has led oil companies to 

pursue offshore drilling all along the continent’s At-
3

lantic coast. The U.S. Geological Survey (USGS) has 

estimated that West Africa alone also contains 120 billion barrels of oil equivalent (BOE) of undiscovered 

petroleum resources.

Second, despite this accelerating oil and gas exploration, the continent is enormous and remains largely 

underexplored for hydrocarbons. While Africa today 

holds 8 percent of proven global oil and gas reserves, 

it accounts for 20.4 percent of the world’s land mass 

(and 22.4 percent when Antarctica is excluded).3 It 

also has a coastline of 16,000 miles (26,000 kilometers [km]) with Exclusive Economic Zones (EEZs) extending 200 miles offshore4

 and seven island nations 

with their own large EEZs.5 There were only 1,000 

wells drilled onshore and offshore in Africa in 2011 

compared with 18,500 drilled in Alberta, Canada, in 

2005.6 While cumulatively, some 20,000 wells have 

been sunk in North Africa7 and 15,000 wells have been 

drilled in West Africa, only 500 have been drilled to 

date in East Africa.8 Even with the modest number of 

wells drilled in East Africa, the last 5 years have seen 

the discovery of major oil and gas reserves in Uganda, 

Kenya, Mozambique, and Tanzania—proving that 

several of Africa’s remaining unexplored sedimentary 

basins promise to contribute an even larger share of 

global production and reserves in the future.9

 One 

less conventional view supported by a recent Ernst 

and Young report and scholar Paul Collier is that the 

scale of what is likely to happen in Africa is not widely 

appreciated and that: 

future discoveries and resulting exports of resources 

(including oil and gas) will be around five times their 

current level (based on what remains unexplored in 

Africa versus currently known sub-soil assets), and 

that this will have a profoundly positive impact on 
4

Africa’s future growth and strategic positioning in the 

global economy.10

Good Governance in the African Energy Sector and 

Avoidance of the Resource Curse.

While this monograph is primarily about oil and 

gas exploration and production, the author will take 

a moment to stress that good governance in Africa’s 

oil and gas industry will play a critical role—indeed 

arguably the central role—in how much the continent 

and its people will benefit from this bonanza of energy 

wealth.11 In this regard, the author’s home institution, 

the Africa Center for Strategic Studies, held a conference in Abuja, Nigeria, in 2005 about the interplay between Africa’s energy future and human security. The 

key conclusions of this conference are still valid: 

Increased [oil and gas] wealth without adequate constitutional, legal, regulatory, and policy reforms could 

exacerbate human security challenges [in Africa and] 

include an overreliance on oil and gas revenues, weak 

political and economic governance, corruption, relative poverty, and resource tensions. The complex linkages among human security, weak governance, and 

the oil and gas sectors highlight the primacy of internal threats in African countries including community 

grievances, sabotage, theft, and militant groups.12

This monograph discusses good governance mainly 

in the context of the need to attract foreign investment 

and reduce risk. While its central focus is not on good 

governance and human security, this is only because 

of the practical need to limit the scope of this paper 

to the already expansive issue of African oil and gas 

exploration and production. 
5

I. IN THE BEGINNING: 

AFRICAN OIL AND CONTINENTAL DRIFT 

THEORY

 Perhaps the most important geological concept for 

the layman to grasp Africa’s bright future in oil and 

gas is the theory of continental drift. In paleogeography, the study of historical geography, Gondwana is 

the name given to the more southerly of two supercontinents (the other being Laurasia) that existed from approximately 180 to 510 million years ago. Gondwana, 

also called Gondwanaland, incorporated present-day 

South America, Africa, Madagascar, Saudi Arabia, India, Australia, and Antarctica. Under this theory, the 

waters off much of the Americas today are a mirror 

image of the rich oil deposits off the western side of 

Africa, and vice versa. Geological evidence suggests, 

for example, that Morocco, where there is now feverish offshore exploration, was attached to present-day 

Mexico, whose rich petroleum resources have been 

known for decades; Ghana, where the huge Jubilee oil 

field was discovered in 2007, was attached to presentday French Guyana, where an over one billion-barrel 

field was discovered in 2011; and Angola, where the 

first offshore field was discovered in 1966, was attached to Brazil, where exploration began in 1968, but 

the huge offshore oil fields at Campos were discovered more recently.13

Two geological vocabulary terms that are important to understanding African oil and gas exploration 

are rifts and grabens. A rift is a linear zone where the 

Earth’s crust and its outermost shell, or lithosphere,14

are being pulled apart.Rifts are important because the 

sedimentary rocks associated with continental rifts 
6

often host important deposits of hydrocarbons.15 A 

graben is a depressed block of land bordered by parallel faults.16 Grabens are also commonly associated 

with the presence of hydrocarbons. The East Africa 

Rift Valley, for example, is rich in grabens and, not 

coincidentally, is also increasingly recognized in the 

oil industry as a highly promising “petroleum province.” A third geological vocabulary term important 

for Africa is what is called a pre-salt layer, which is a 

geological formation regularly found on the continental shelves off the coast of Africa and the Americas. 

Pre-salt layers are important because they often hold 

significant petrochemical resources. For the Atlantic, 

oil and natural gas tend to lie below an approximately 

2,000-meter (m) deep layer of salt, itself below an approximately 2,000-m deep layer of rock under 2,000-

3,000-m of water.17

Much of the oil and gas found offshore in Africa 

and the Americas has been in pre-salt layers, for which 

seismic imaging has improved considerably in recent 

years. The following statement from U.S. firm Cobalt 

International captures the essence of the importance 

of continental drift theory for the entire western or 

Atlantic side of Africa from Morocco to South Africa: 

The pre-salt geology of offshore West Africa has many 

similarities to that of offshore Brazil, the location of 

a number of recent super-giant discoveries. Existing 

on-shore and near-shore pre-salt fields in West Africa 

provide additional support for the existence of deepwater pre-salt opportunities. Over the past 150 million 

years, rifting and separation of South America from 

Africa has occurred along much of the Atlantic Margin. The pre-rift geology below the salt [layer] remains 

largely unaltered and is consistent from one continent 

to the other. This has resulted in a series of analogous 
7

basins on both sides of the Atlantic. Each of these basins contains a world-class oil-prone source rock and 

an extensive salt layer, which acts as a regionally extensive seal.18

The eastern, or Red Sea/Indian Ocean, side of Africa has a similar geological story, albeit more complex. 

The East African Rift System is the largest continental 

rift system on the Earth’s surface and actually extends 

from the Jordan in the Middle East to Mozambique in 

southern Africa. Within the East African Rift System 

are two branches of note: the East Rift Valley (often 

called the Great Rift Valley) and the Western Rift Valley, both in central-eastern Africa. The East Rift Valley System is increasingly felt to also include a third, 

southwesterly branch ending in Namibia. The northern part of East Africa was also part of the Gondwana 

mega-continent and drifted apart from the modern 

day Arabian Peninsula. Since the Red Sea Basin has 

had several large oil and gas discoveries in Egypt, Sudan, and Saudi Arabia, oil and gas prospectors have 

recently noted with great excitement the geological 

similarities between the Darin and Nogul Basins in 

Somalia and the Masila and Marib-Shabwa Basins in 

oil-rich Yemen. Anglo-Irish Tullow Oil used the discovery of oil in Uganda in 2006 to look for rift valley 

analogies in Kenya and Ethiopia. This same theory 

of continental drift has also been applied to oil and 

gas found along the coast of Madagascar since that 

island nation shares similar geological patterns with 

Kenya, Tanzania, and Mozambique, to which it was 

connected 145 million years ago. The Seychelles is also 

thought to have hydrocarbon potential because it can 

also be reconstructed to a position adjacent to Somalia 

and as a northern extension of Madagascar. 
8

II. A GEOLOGICAL MAP OF AFRICA

Most readers interested in Africa have some familiarity with the political division of the continent 

into regional economic communities in West, Central, 

South, East, and North Africa, such as the Economic 

Community of West African States (ECOWAS). This 

monograph, however, eschews the traditional political map of Africa in favor of a geological map. The 

author has chosen this approach because he is convinced that a geological map will enable readers to 

more clearly understand and visualize both the interconnected nature of oil and gas fields straddling countries, and the political imperative in many cases for 

future cross-border cooperation in jointly developing 

related resources and infrastructure. 

Major Country-level Trends in Africa’s Geological 

Sub-Regions. 

The six geological sub-regions of Africa presented 

here are: 

1. The North African Margin, geologically includes 

northern Morocco roughly east of the Strait of Gibraltar, which is part of the North Africa Margin.19 It also 

includes Algeria, Tunisia, Libya, and Egypt.

2. The Atlantic Transform Margin20 runs geologically via from Morocco roughly west of the Strait of 

Gibraltar, all along the western coast of Africa to western South Africa. Also included are the countries of 

Mauritania, Senegal, Gambia, Cape Verde, Guinea 

Bissau, Guinea, Sierra Leone, Liberia, Cote d’Ivoire, 

Ghana, Togo, Benin, Nigeria, Sao Tome and Principe, 

Cameroon, Equatorial Guinea, Gabon, Congo (Braz-
9

zaville), the Democratic Republic of the Congo (DRC), 

Angola, and western Namibia. (The former Spanish 

colony and currently disputed territory of Western Sahara is also included in this sub-region.)

3. The East Rift Coastal21 is a branch of the larger 

East African Rift System and runs geologically from 

the Red Sea coast of Egypt, Sudan, Eritrea, and Djibouti southward to Somalia, Ethiopia, eastern Kenya, 

eastern Tanzania, eastern Mozambique, western Madagascar, eastern South Africa, and the island nations 

of the Comoros and Seychelles. (Juan de Nova, which 

is part of the French Southern and Antarctic Lands, 

is discussed jointly with Madagascar;22 Mauritius is at 

best distantly related to this System, but is grouped 

here for the sake of simplicity.)

4. The West Rift Valley, a second branch of the East 

African Rift System, runs geologically from southeastern Sudan, the country of South Sudan, Uganda, eastern DRC, Rwanda, Burundi, western Tanzania, Zambia, Malawi, and western Mozambique.

5. The Central Africa Rift System23 includes a series 

of basins running through northern Cameroon, southern Chad, and northern Central African Republic, intersecting basins such as Jongolei and Melut that also 

extend into South Sudan. Three other countries in inland West and Central Africa do not fit our model, but 

are included in this section for the sake of simplicity: 

Mali, which has basins extending into its neighbors, 

Mauritania, Algeria, and Niger; Niger, whose basins 

extend into Mali, Algeria, Libya, Chad, and Nigeria; 

and Burkina Faso, which has no known hydrocarbons.

6. Southern Africa is at the end of both the Atlantic 

Transform Margin in the west to the East African Rift 

in the east. The Southern Africa geological region also 

has such complexities such as the Karoo Basin shale 
10

oil in its west and coal-bed methane in its northeast. 

Included here are eastern Namibia, Botswana, South 

Africa, Zambia, Zimbabwe, and eastern Mozambique. 

There are no known hydrocarbons in Swaziland and 

Lesotho.

For these six geological regions, the author summarizes here the highlights of information found in 

the country profiles in Appendix 1.

1. The North Africa Margin—Historical Leader in Oil 

Production, but Shaken by Political Instability.

Geologically speaking, the North Africa Margin 

could be taken roughly to include Algeria, Tunisia, 

Libya, and Egypt. Cumulatively, the countries of 

North Africa, here excluding Morocco, have historically been the single most important oil and gas region 

in Africa. In 2010, Libya, Algeria, and Egypt were, respectively, the third, fourth, and fifth largest oil producers in Africa after Nigeria and Angola. Algeria, 

Egypt, and Libya were even more dominant in natural 

gas production, occupying the number one, two, and 

four positions in 2009 (with Nigeria third and Equatorial Guinea fifth). North Africa has been primarily an 

onshore “conventional play,” but increased offshore 

exploration across the sub-region (including eastern 

Morocco) promises significant new discoveries. The 

sub-region has broadly remained open to IOCs, with 

decades-long history of activity by both foreign investors and NOCs, but with bouts of resource nationalism that have periodically dampened the enthusiasm 

of foreign investors.

At present, North Africa is beset with political and 

economic/demographic challenges. Politically, the 

Arab Spring set off regime changes in Tunisia, Egypt, 
11

and Libya that have made the sub-region more democratic, but less stable in the short-term. The current political uncertainty in North Africa, including the terrorist attack by al-Qaeda in the Islamic Maghreb (AQIM) 

at the Amenas gas project in Algeria in January 2013

and ongoing, low-intensity fighting between militia 

groups in Libya, is having significant implications for 

the region’s oil and gas industry, both in terms of disrupted operations and postponed investment. The decision by U.S. firm ConocoPhillips in December 2012

to sell its Algerian assets, and the decisions by AngloDutch Shell and U.S. firm Chevron to abandon drilling and exploration in several blocks in Libya, reflect 

deep concern about the risk-return calculus in North 

Africa. Algeria, Tunisia, Libya, and Egypt face similar economic/demographic challenges that have also 

caused domestic demand for oil and gas to soar: heavily subsidized fuel prices, rapidly rising populations, 

and greatly increasing car use. This increased demand 

for oil and gas has, in turn, caused the amount available for export to decline, thereby also sharply reducing government revenues.

In Algeria, the unfavorable 2005 hydrocarbon law 

and a 2006 presidential decree have dampened the enthusiasm among IOCs for investment in the country’s 

oil and gas sector, contributing to a 20 percent drop in 

hydrocarbon production over the last 5 years. In January 2013, Algeria’s parliament approved amendments 

to the law, but some observers remain pessimistic that 

these changes will turn around declining foreign investment. One apocalyptic analysis even predicted 

that Algeria could run out of available oil to export 

after 2023 because of soaring domestic demand and 

falling production.
12

In Libya, political volatility and a tenuous security 

situation following the 2011 civil war have also dampened foreign investment, which had been on the resurgence in the mid-2000s after the United Nations (UN) 

and United States lifted sanctions. For the next few 

years, output in Libya is expected to stay near the 1.7

million barrels per day (bpd) produced in 2010. After 

this, output may resume a slow upward path if new 

fields come into production to replace existing fields 

entering their decline phases. One reason for longerterm optimism about Libya’s energy export potential 

is that, with proven oil reserves of 47.1 billion barrels, 

the largest in Africa, the country is simply too important to ignore.

Post-Arab Spring, the oil and gas sectors of Tunisia 

and Egypt have fared better. Tunisia had a modest upstream industry to begin with, with declining production for much of the last 20 years and no exports, but 

with new exploration that could potentially reverse 

this decline. Political unrest has not directly affected 

foreign oil investors in Egypt, as the top producing 

regions—the offshore Nile Delta and the Western Desert—are far from population centers. Overall, Egyptian oil production has been declining, but new discoveries have continued and promise hope to reverse 

this decline. Since 2000, oil output in the Western Desert has doubled, for example, and now accounts for 

around 28-30 percent of Egypt’s total oil production.

2. Atlantic Transform Margin—Common Offshore Geology with Latin America Highly Promising.

The Atlantic Transform Margin runs from Morocco roughly west of the Strait of Gibraltar, all along 

the western coast of Africa via the Gulf of Guinea, to 

western South Africa. (The DRC is addressed later in 

the section on the Central Africa Rift System.) 
13

This geological sub-region is dominated by one of 

the old lions (Nigeria) and one of the new lions (Angola). The outlook for Organization of Petroleum Exporting Countries (OPEC) member Nigeria, Africa’s 

largest oil producer, hinges on resolving a number 

of major issues, including civil conflict in producing 

regions; improving the transportation infrastructure, 

whose deteriorated state has led to sporadic disruptions to supply; the inability of the Nigerian National 

Petroleum Company (NNPC) to fund its share of investment in joint ventures with international companies; and delays in agreeing to a new Petroleum Industry Bill, which has paralyzed investment in recent 

years.24 ConocoPhillips’ pessimistic view of Nigeria’s 

investment environment was behind the $1.79 billion 

sale in January 2013 of its Nigeria operations.

Although crude oil production in Angola, Africa’s 

second largest oil producer and an emerging major 

gas supplier, slipped to 1.79 million barrels per day 

(bpd) in 2011, the government is targeting 2 million 

bpd production levels by 2014. Successful exploration 

in Angola’s pre-salt formations continues to drive optimistic oil production forecasts for the country and 

hopes that new deepwater discoveries will yield more 

than enough oil to offset declines at existing fields.25

South-Central Africa: Namibia to Sao Tome and 

Principe. South of Angola, Namibia attracted investment by major IOCs in 2012 on the bet that its coastal 

shelf may mirror that of Brazil across the Atlantic 

Ocean, where the Tupi discovery in 2007 was the 

biggest find in the Americas in 3 decades.26 North of 

Angola, Congo (Brazzaville) was still Africa’s seventh 

largest oil producer in 2010, although its oil production is in decline and potential gas development is limited by a lack of infrastructure. Oil and gas production 
14

could increase, however, if the country’s deepwater 

offshore potential27 is realized. Congo also has a pilot 

oil sands project and has agreed to jointly exploit the 

Lianzi cross-border oil field with Angola. 

Crude oil production in Equatorial Guinea, Africa’s 

eighth largest producer in 2010, has been declining as 

a result of maturing oil fields, but with the recent startup of the Aseng oil and gas-condensate field and the 

anticipated start-up of the Alen gas-condensate field in 

late-2013, the development of these new fields are projected to revive liquids production in the near term.28

Oil output in Gabon has dropped about 40 percent 

from its peak of 370,000 bpd in 1997, causing Gabon to 

fall to the ninth largest oil producer in Africa.29 In the 

long run, Gabon’s oil production will depend on the 

success of new exploration, particularly of deepwater, 

pre-salt fields, interest in which has been piqued by 

recent offshore Brazil pre-salt discoveries.30

While Cameroon’s oil production has been declining since 1985,

31 the government announced that it expected production would rise about 59 percent by the 

end of 2012 because of the development of new fields. 

There have been significant recent discoveries of oil 

and gas condensates in Cameroon’s two main basins.32

The northern Bakassi region is considered to be rich 

in oil and gas, but had little exploration until recently 

due to lingering concerns about a territorial dispute 

with Nigeria, which was adjudicated in Cameroon’s 

favor in the mid-2000s.33 To date, there have not been 

any major commercial oil or gas finds in Sao Tome and 

Principe, but there is guarded optimism about future 

discoveries. Three oil and gas stories for Sao Tome and 

Principe concern 1) exploration and production (E&P) 

in the Joint Development Zone (JDZ) with Nigeria; 2) 

E&P in Sao Tome’s EEZ; and 3) plans to build a tank 
15

farm and oil transshipment port for international use 

firms operating in the Gulf of Guinea sub-region. 

Ghana Discoveries Bring Hope from Benin to Morocco. The 2007 discovery of Ghana’s Jubilee Field is 

transforming the country’s oil and gas industry and 

estimations of oil and gas potential all along Africa’s 

Atlantic coast. Jubilee and other successes in adjacent 

fields bode particularly well for neighboring offshore 

developments in the Atlantic Transform Margin from 

Benin and Togo to the west, to Cote d’Ivoire, Liberia, 

Sierra Leone, and Guinea to the east.34 To date, Benin had limited production at its Seme offshore field, 

which may reopen in the future. In June 2012, oil was 

discovered in the Dahomey Basin in Togo, which is 

part of the Atlantic Transform Margin extending from 

the Keta Basin in eastern offshore Ghana eastward 

through Togo and Benin to the Mont Okitipupa Basin 

in Nigeria.35

Cote d’Ivoire has proven reserves of only 100 million barrels of oil and 1.1 trillion cubic feet (tcf) of natural gas, but oil and gas finds in neighboring Ghana 

are spurring additional exploration and have already 

led to a number of new discoveries since 2010. In Liberia, a new offshore oil discovery in February 2013

boosted the already considerable optimism about the 

possibility of a new offshore hydrocarbon sub-province known as the West Africa Transform Margin. 

Recent oil discoveries in Sierra Leone confirmed that 

the main reservoir and source elements in the Jubilee 

field in Ghana are present in the Sierra Leone/Liberia deepwater basin.36 Exploration remains at an early 

stage, but prospects look good for Sierra Leone to become a new frontier for oil and gas.37

In Guinea, IOCs are teaming up to “apply their 

successful exploration experience on the Atlantic 
16

Margin . . . particularly the [West Africa] Transform 

Margin play that is present in the Guinea acreage.”38

There have been recent oil discoveries in both GuineaBissau’s offshore blocks and its JDZ with Senegal, but 

the country’s reputation as a target for foreign investment has been severely damaged by perceptions that 

it had devolved into a narco-state under the influence 

of Latin American drug cartels.39

The main oil and gas E&P areas in Senegal are in 

offshore blocks in Senegal’s territorial waters or EEZ, 

and in Senegal’s JDZ with Guinea-Bissau. As with 

Mauritania, in pre-rift time, Senegal was considered 

to be adjacent to Mexico before the African and American continents pulled apart.40 Tullow is optimistic 

about Senegal because an exploratory well drilled in 

2011 had the same cretaceous turbidite play that led 

Tullow to discover the Jubilee Field in Ghana. There 

are no known oil or gas reserves in the Gambia, but 

the country has good prospectivity for hydrocarbons since the area marks the northern extent of the 

Casamance-Bissau sub-basin, which forms part of 

the Mauritania-Senegal-Gambia-Guinea Bissau Coast 

Basin,41 also known in the industry as the “MSGBC” 

Basin, which itself is part of the geological sub-region 

known as the North-West Africa Atlantic Margin.

Mauritania is a frontier exploration country where 

the limited oil and gas production has been disappointing so far, but where promising offshore and 

onshore prospects have attracted Asian, Australian, 

European, and U.S. oil firms. Mauritania has the same 

geological source rocks as found in Ghanaian oil 

fields.42 Some experts have suggested that oil and gas 

reserves discovered in neighboring Mauritania could 

stretch as far as Cape Verde, but there has been only 

limited exploration so far in this island nation and its 

huge EEZ. 
17

Compared to its prolific eastern neighbor Algeria, 

Morocco has had a modest upstream industry. However, most sedimentary basins in Morocco onshore 

and offshore are still largely unexplored,43 with IOCs 

attracted to the country’s considerable potential and 

the government’s favorable tax regime. Both Morocco 

and the Saharawi Arab Democratic Republic (SADR)44

have granted exploration licenses to IOCs in Western 

Sahara despite a UN resolution against such deals 

until the issue of the territory’s sovereignty has been 

resolved. However, no OICs have been carrying out 

drilling in this disputed territory.

3. East Rift Coastal Region—Geological Links to OilRich Saudi Peninsula, Madagascar.

The East Rift Coastal region is a branch of the East 

African Rift System, which runs geologically on the 

continent from the Red Sea coast of Egypt to eastern 

South Africa. 

Sudan/South Sudan: Continued Conflict, but 

Bound Together by Pipeline. After a decade of war, 

Sudan and South Sudan signed a peace agreement in 

2005 after a referendum that led to the independence 

of South Sudan in July 2011. Sudan and South Sudan, 

which, when aggregated together were the sixth largest oil producer in Africa in 2010, saw average daily 

production in 2011 fall to 425,000 barrels, a significant 

decline from 470,000 bpd in January 2011. A dispute 

over pipeline and export transit fees lingered postindependence, leading South Sudan to halt exports 

for several months, until March 2013. South Sudan is 

eager to export its oil via Kenya to reduce its dependence on Sudan.

Eritrea, Djibouti, and Somalia: Geological Links 

to Oil-Rich Yemen. Eritrea’s great potential over the 

long term as an oil and gas producer—with geologi-
18

cal analogues both in Uganda’s rich petroleum basin 

and with Yemen across the Red Sea—has not been 

realized, in part due to political instability, including wars with Ethiopia and an autocratic regime that 

was subjected recently to UN sanctions that are still 

ongoing. The Red Sea Basin, of which Djibouti is part, 

has had several discoveries in its northern area in Sudan, Egypt, and Saudi Arabia, and there are also analogues with the large Jurassic oil fields located nearby 

in Yemen.45 Djibouti’s Guban Basin extends into Somalia’s northern province of Somaliland, where there 

have been oil seeps and recovery of oil from wells 

drilled in previous decades. 

Estimates of onshore and offshore reserves of 

Somalia vary greatly, but run as high as 110 billion 

barrels of oil46—a staggering figure that, if proven 

true, would give this country the continent’s largest 

reserves. Independent international E&P companies 

are presently investing in Puntland and Somaliland 

despite the legal and political uncertainties. Parts of 

Puntland are geological extensions of basins in oil-rich 

Yemen, while Somaliland contains geological basins 

similar to both Yemen and Uganda, where millions of 

barrels of oil reserves have been discovered.

Ethiopia and Kenya: Crossroads of Several Geological Basins. There are five sedimentary basins in Ethiopia with prospects for hydrocarbons. Some geologists 

believe that there are several tcf of gas condensate in 

Ogaden, which they see as just one of a large number of promising East African coastal basins. Ethiopia 

is also in part of the Turkana Rift Basin, shared with 

Kenya. This basin is similar in geology to the Lake Albert Rift Basin, where large amounts of oil have been 

discovered in Uganda. Ethiopia also has oil deposits 

on the border with Eritrea to the north and Sudan to 

the west. 
19

Major oil discoveries in Uganda in 2006 and natural 

gas discoveries in Mozambique and Tanzania in 2010 

have created expectations that Kenya is part of a new 

regional hydrocarbon province. Kenya has four large 

sedimentary basins offshore and onshore. These are 

found in southeast Kenya, which has similar geology 

to Madagascar, and in the Tertiary Rift Basin in western Kenya, which borders Sudan and Ethiopia to the 

north, Uganda to the east, and Tanzania to the south.47

In 2012, discoveries were made of oil in the Lochikar 

onshore sub-basin48 and of natural gas offshore.49

Tanzania and Mozambique: A New Hydrocarbon 

Frontier. Recent, large discoveries of offshore natural 

gas in Tanzania and Mozambique have led observers to dub these two countries as Africa’s “newest 

lion cubs,” and led to soaring expectations about East 

Africa’s potential as a new hydrocarbon frontier. Recent discoveries in Tanzania have boosted its natural 

gas reserves to over 34 tcf, leading to hopes for the 

country’s first multitrain liquefied natural gas (LNG) 

development.50 In February 2013, the government announced that it would soon issue a license to an IOC 

to explore in Lake Tanganyika, an area that is also currently claimed by Malawi. 

Mozambique has two main sedimentary basins: the 

Rovuma Basin in the northeast adjacent to the Tanzanian border and the Mozambique Basin in the south.51

Rovuma Area 1 has up to 100 tcf of natural gas in place, 

making it among the world’s most significant hydrocarbon finds in the last decade.52 Rovuma Area 4 has 

an estimated 75 tcf of natural gas in place. Several oil 

companies are also carrying out exploration activities 

in the Urema Graben in central Mozambique, which is 

in the southern part of the East African Rift System.53

In Mozambique, U.S. firm Anadarko and Italy’s ENI 
20

are jointly working to advance an LNG park drawing 

upon Areas 1 and 4’s gas to produce approximately 50 

million tons of LNG per year—enough to elevate the 

country to one of the world’s largest LNG exporters.54

Island Nations and Territory: Madagascar, Comoros, Seychelles, Mauritius, and Juan de Nova. The 

island nation of Madagascar has five sedimentary basins.55 The onshore part of the Morondava Basin is a 

proven petroleum province with onshore discoveries 

of oil sands and subsurface heavy oil deposits exceeding 20 billion barrels. The offshore portion of the basin 

is considered to be part of the same petroleum system, but extending into a deeper geologic setting that 

may yield lighter oil discoveries.56 Political instability 

has been a serious impediment to foreign investment 

in Madagascar’s oil and gas industry and only made 

worse by threats by the transitional government to expropriate major oil fields.57

In the Mozambique Channel between Mozambique and Madagascar lie the Juan de Nova islands, 

which are controlled by France and where exploration is occurring east of the gas-rich Rovuma Basin 

in Mozambique. The island nation of the Comoros 

awarded its first oil exploration license in March 2012 

for acreage adjacent to offshore Area 1 and Area 4 of 

Mozambique’s Rovuma Delta. Global interest in the 

waters off the island nation of the Seychelles has also 

been sparked following recent East African successes 

in Mozambique and Tanzania.58 Nearly 70 percent of 

the population of the Indian Ocean island nation of 

Mauritius is of Indian origin. The Indian oil company 

ONGC has sought oil and gas exploration rights in 

Mauritius, which has no known hydrocarbons.59
21

4. West Rift Valley—Oil Discoveries in Uganda Bring 

Hope to Landlocked Nations. 

The West Rift Valley is a second branch of the East 

African Rift System, running geologically from Sudan, 

South Sudan, Uganda, eastern DRC, Rwanda, Burundi, western Tanzania, northeastern Zambia, Malawi, 

and western Mozambique. Only Uganda, the DRC, 

Rwanda, Burundi, and Malawi are addressed here. 

Uganda is highly attractive to investors because 

the country’s oil discovery rate is an extraordinary 90 

percent. Estimates of Uganda’s oil reserves have varied widely, with the major IOCs indicating 1 billion 

barrels and the government claiming 3.5 billion barrels. First, oil production has been repeatedly delayed 

because of disagreements between the government 

and IOCs; the current earliest start date is 2017, with 

full capacity unlikely to be reached before 2020. While 

there are some oil and gas fields in the narrow coastal 

strip of offshore DRC, the future of oil exploration for 

this troubled giant, Africa’s second largest nation, lies 

principally in the east, in the Albertine Graben, where 

oil has already been discovered in significant quantities across the border in Uganda. Unfortunately, the 

DRC’s government has mishandled the allocation of 

exploration blocks in eastern DRC, awarding some 

blocks as many as three times to different companies. 

Rwanda has no oil production, but does have 

methane gas reserves along its borders with the DRC 

and Tanzania. Exploration is ongoing in the East Kivu 

Graben, located beneath Lake Kivu, which is part of 

the southern extension of the Albertine Graben in 

Uganda. Burundi announced in September 2012 that 

hydrocarbons had been found in Lake Tanganyika 

and the Rusizi plain. Some experts view the lake’s geology as analogous to the tertiary rift system at Lake 

Albert to the north between the DRC and Uganda. 
22

Malawi currently has no oil or gas production, but 

is part of the East African rift system, which is a proven exploration province with prolific oil discoveries 

in Sudan, Uganda, and Kenya. Until a long-standing 

border dispute with Tanzania can be resolved, exploration efforts on the contested section of Lake Malawi 

may be delayed.

5. Central African Rift System—Complex Basin Systems, Rocked by Recent Instability Except for Chad. 

The Central Africa Rift System includes a series 

of basins running from Cameroon through southern 

Chad, northern Central African Republic (CAR), and 

Sudan, intersecting basins such as the Jongolei and 

Melut Basins that also extend into South Sudan. Also 

addressed in this section are two other countries in 

inland Africa, Niger, and Mali, which do not fit our 

model. 

Chad was Africa’s 10th largest oil producer in 2010. 

It shares with its neighbors three sedimentary basins 

known for oil and gas potential: 1) the Koufra–Erdis 

Basin in the north shared with Libya; 2) the Chad 

Basin in the center-west shared with Niger, northern 

Nigeria, and Cameroon; and 3) the Sud Basin in the 

south shared with CAR and Sudan. Since 2003, Chad 

has been exporting oil via a 1,000-km pipeline through 

neighboring Cameroon to the port of Kribi, on the 

Gulf of Guinea. In collaboration with Sudanese partners, China National Petroleum Corporation (CNPC) 

restarted oil exploration in 2011 in northeastern CAR 

near the border with Chad. Despite prospects for oil 

discovery, petroleum development and production in 

the CAR will likely be held back by the country’s political instability. 
23

Niger negotiated an agreement with Chad in July 

2012 to use Chad’s pipeline to export some of its future 

production. Niger has three distinct areas of oil and 

gas potential: Agadem, bordering Chad to the east; 

Tenere, with similar oil-producing basins as found in 

Libya, Chad, and Sudan; and Kafra, a continuation 

of a rift basin in northern Niger extending up to the 

Algerian border. Mali, to the west of Niger, is largely 

unexplored for hydrocarbons. Around one-half of the 

country overlies sedimentary basin, but only five exploration wells have ever been drilled. Further exploration in northern Mali is unlikely until the country’s 

political situation stabilizes in the aftermath of a recent coup and attempted takeover of the north by a 

terrorist and secessionist groups.

6. Southern Africa—At the End of Three Major Geological Regions, Plus Shale, Coal-Bed Methane Potential.

Southern Africa is at the end of the Atlantic Transform Margin in the west, the West Rift Valley in southcentral Africa, and the East African Coastal Rift in the 

east. The complexities of this geological sub-region 

also include the Karoo Basin shale oil in its west and 

coal-bed methane in its northeast. South Africa’s oil 

and gas reserves are currently small, but could increase dramatically in the coming years. Offshore exploration in South Africa is intensifying, spurred by: 

1) massive gas discoveries to the east in Mozambique 

in 2010, 2) modest discoveries in the Bredasdorp Basin 

to the south, and 3) encouraging results in the Orange 

Basin in the east, south of Namibia. Onshore, large 

IOCs are betting that the geological strata running 

southward from Uganda and the Great Lakes extend 

to South African territory.
24

Neither Botswana nor Zimbabwe has any proven 

oil or gas reserves, but both have potential to become 

producers of coal-bed methane gas, the latter only if 

its government creates a more hospitable environment for foreign investment. Zambia has no proven 

oil or gas reserves, but with oil discovered in Uganda 

and coal-bed methane in Botswana, Zambia is hopeful 

that commercially viable hydrocarbon deposits will be 

found. While Lesotho is in the Karoo Basin, geological 

analysis suggests that it is unlikely to be the site of 

commercially viable shale gas. Swaziland also has no 

proven hydrocarbons. 

III. AFRICAN OIL AND GAS PRODUCTION 

AND RESERVES

Major African Producers in a Larger 

Global Context.

Africa is already a huge energy exporter, and its 

570 million TOE exports represent 43 percent by dollar value of the continent’s total exports. As shown in 

Table 1, five countries—in order of decreasing output—accounted for 82.3 percent of the continent’s oil 

production in 2010: Nigeria, Angola, Libya, Algeria, 

and Egypt. Other smaller oil-producing countries 

are Cameroon, Chad, Congo, Cote d’Ivoire, the DRC, 

Equatorial Guinea, Gabon, Ghana, Sudan/South 

Sudan, and Tunisia, with a limited number of other 

countries such as Senegal and South Africa with daily 

production that is negligible.60 In 2009, the major African natural gas producers were, in order of decreasing 

importance, Algeria, Egypt, Nigeria, and Libya. These 

figures for natural gas are dated, however, and in the 

last 4 years, Nigeria has started to monetize significantly much more of its natural gas production, while 
25

Angola started exports in 2013 at its first LNG train 

after repeated delays.61

Source: “Africa Oil and Gas: A Continent on the Move,” Ernst & 

Young, 2011, EYG no. DW0100 WR, no. 1107-1271904, available 

from www.ey.com/GL/en/Industries/Oil---Gas/Africa-oil-and-gas--acontinent-on-the-move---Regional-prospects-and-opportunities-in-theoil-and-gas-sector.

Table 1. Ten Largest African Producers of Oil 

and Natural Gas.

With 54 countries on the African continent, along 

with the disputed area of Western Sahara, there are 

various metaphors that could be used to represent 

the rise of new oil producer nations in Africa. One 

author referred to long-established oil and gas producers such as Algeria, Libya, and Nigeria as “old 

lions,” newer producers such as Angola as a “young 

Oil: 2010 (000 bpd) Gas: 2009 (bcf/d)

Nigeria 2,065 Algeria 7.88

Angola 1,790 Egypt 6.07

Libya 1,550 Nigeria 2.25

Algeria 1,250 Libya 1.54

Egypt 740 Equatorial 

Guinea 0.62

Sudan 480 Mozambique 0.35

Congo 270 Tunisia 0.35

Equatorial 

Guinea 255 South Africa 0.18

Garbon 245 Cote d/Ivoire 0.15

Chad 100 Angola 0.07

Others 237 Others 0.13

Total 8,982 Total 19.58
26

lion,” and new, emerging producers such as Ghana as 

“new cubs.” Another industry observer focused on regional agglomerations of producer nations to describe 

three new “clubs”: (1) Emerging West Africa—Angola 

deepwater (pre-salt), Ghana deepwater, Mauritania 

deepwater, Ivory Coast deepwater, Gabon deepwater; 

(2) East Africa—Mozambique deepwater, Tanzania 

deepwater, Kenya onshore and deepwater; and, (3) 

Onshore Central Africa—Chad, Uganda, Niger, Sudan, and South Sudan.62

This observer noted that several other countries 

that are not part of these clubs yet, such as Liberia, 

Sierra Leone, Somalia, South Africa, and Morocco, 

have seen new, successful basin tests and/or discoveries, but that these remaining countries have proven 

reserves that are of insufficient scale, with cumulative 

Africa totaling 600 million BOE, or just 1 percent of 

the total for Africa.63 (The classification of these newly 

emerging producer nations such as Sierra Leone, and 

indeed perhaps two dozen of the countries described 

previously, thus enters into definitional issues of different categories of “reserves,” an issue addressed in 

Appendix 2.)

Africa Boosting Oil and Gas Reserves.

As shown in Table 2, Africa had proven oil reserves 

of 132.4 billion barrels at the end of 2011, equivalent 

to 41.2 years of current production. This was an increase of 154 percent over the 1980 figure of 53.4 billion.64 During the period from 2000 to November 2012, 

cumulative discoveries in Africa totaled 60-70 billion 

BOE (2P) or almost 10 percent of the total global additions of over 800 billion BOE, of which 380 billion BOE 
27

and 420 billion BOE, respectively, were conventional 

and unconventional resources. During this same period, new discoveries in emerging West Africa were 

19.2-22 billion BOE, in East Africa 12.5-20 billion BOE, 

and in onshore Central Africa 3.2-4 billion BOE. More 

than half of Africa’s new discoveries were added since 

2007, with a large part being gas. Oil explorers in Africa had strong years in 2010 and 2011, when they found 

the equivalent of five billion barrels of oil each year, 

with 2012 being an even stronger year, with volumes 

approaching 10 billion barrels.65

It is also notable that the sources of these new 

reserves have become more geographically spread 

within Africa over time and that this trend toward increased geographical diversification should continue 

in the future. Recent discoveries in Africa have been 

made in all settings—onshore, below lakes, in shallow 

water, deepwater, in new countries and/or basins with 

little or no exploration history. Excluding new discoveries in North Africa, there were two major waves of 

exploration successes in the last 25 years. Nigeria was 

a leader in the 1990s in a series of deepwater discoveries, along with Angola, in proving 16 billion barrels 

of oil. A more recent wave, which is not reflected in 

Table 2, likely because of issues related to the definition of “proven reserves,” can be dated to the 2000s 

and involves a new series of basins elsewhere in subSaharan Africa, including the Mauritania Basin in the 

country of the same name (2001), the Albertine Basin 

in Uganda, which straddles the DRC and the Kenyan 

part of the East African Rift (2006 for Uganda, 2012 for 

Kenya), the Tano Basin in Ghana (2007), the Rovuma 

Basin in Mozambique and Tanzania (2010 in both 

countries), and the Sierra Leone/Liberia Basin in both 

countries (2010 for Sierra Leone, 2012 for Liberia).66
28

Moreover, no unconventional reserves have been 

added to Table 2 despite the fact that the continent 

has substantial, proven heavy oil/bitumen in several 

countries, including Congo (Brazzaville), Nigeria, and 

Madagascar, and potential shale gas, most notably in 

South Africa, Algeria, Libya, Tunisia, and Ethiopia.67

Source: British Petroleum (BP) Statistical Review of World Energy, 

June 2012.

Table 2. Oil-Proven Reserves by Leading 

African Country.

At End 2011

Billion 

Tons

Billion 

Barrels

Percent 

Share of 

Total

Production 

1,000 bpd

Reserves to 

Production 

Ratio

Algeria 1.5 12.2 0.7 1,729 19.3

Angola 1.8 13.5 0.8 1,746 21.2

Chad 0.2 1.5 0.1 114 36.1

Congo(Brazzaville) 0.3 1.9 0.1 295 18

Egypt 0.6 4.3 0.3 735 16

Equatorial Guinea 1.2 1.7 0.1 252 18.5

Gabon 0.5 3.7 0.2 245 41.2

Libya 6.1 47.1 2.9 479 *

Nigeria 5.0 37.2 2.3 2,457 41.5

Sudan and South 

Sudan

0.9 6.7 0.4 453 40.5

Tunisia 0.1 0.4 * 78 15

Other Africa 0.3 2.2 0.1 221 27

Africa Percent of 

World

7 8 7 11
29

Although Africa’s current oil reserves are only 8 

percent of the world’s total, the continent continues 

to play an outsized role “as a pillar of global energy 

security . . . providing a major source of diverse oil 

and gas supply.”68 While Africa has little excess capacity and thus cannot be considered a swing supplier 

per se, the continent’s critical importance becomes 

most apparent when supply shocks take its production off the market, leading to immediate and large 

spikes in world oil prices. This occurred in 2008 after the Movement for the Emancipation of the Niger 

Delta (MEND) carried out attacks in Nigeria,69 and 

in 2011 during civil strife in Libya.70 Africa is also an 

important supplier region because it offers high quality oil, and a large number of producers not bound by 

OPEC quotas.71 Additionally, Africa offers two other 

advantages that are highly relevant for the future: a 

region with relative freedom for IOCs to invest and 

operate,72 and a high proportion of “new oil” projected to be discovered over the next 2 decades compared 

to other regions. With NOCs now managing roughly 

80 percent of the world’s oil supply—compared to 

the 1970s, when the IOCs controlled 85 percent of 

the world’s oil reserves—the competition of Western, 

Chinese, and other emerging market oil companies in 

Africa is all the more intense; not surprisingly, with 

high oil prices and limited amounts of acreage available for exploration in other parts of the world, previously ignored African oil fields are attracting great interest from IOCs.73 Moreover, much of the production 

in Africa is offshore. Although offshore oil is more 

expensive to develop, it is also less susceptible to the 

political instability that often affects onshore production on the continent74 and less vulnerable to potential 

sabotage.75 Offshore E&P also requires high technical 
30

capabilities—a strength of U.S. oil and gas companies. 

Not surprisingly, Africa has been a crucial element in 

the energy diversification strategies adopted in major 

consuming regions, notably Europe and China. Until 

the recent shale oil and gas boom, Africa had also been 

a major part of U.S. energy diversification, with U.S. 

oil imports from Africa for the first time surpassing 

those from the Middle East in 2007.76

According to 2012 estimates by BP and the U.S. 

Energy Information Administration (EIA) in Tables 3 

and 4, Africa will be the world’s fourth most important region for oil and gas production to 2035, after 

the Middle East and Europe/Eurasia, not far behind 

North America, and ahead of Latin America and East 

Asia/Australia. (Africa is likely to become an even 

more important region post-2035, but current projections are not usually made more than 25-30 years into 

the future.) BP predicts that from 2010 to 2030, there 

will be large increases in oil production in the Middle 

East, North America, and South/Central America, 

modest increases in Africa, and production declines 

in Europe/Eurasia, and Asia Pacific. In the case of Africa, BP predicts that African oil production will increase to 512.4 million tons of oil equivalent (TOE) in 

2020, up from 478.2 million TOE, but then fall back to 

497.6 million TOE in 2030. For African natural gas, the 

picture is unambiguously positive, with total production increasing from 188.1 million TOE to 257.2 million TOE in 2020 and 356.8 million TOE in 2030. Similarly, EIA predicted in 2012 that Africa oil production 

would rise to 11.45 million bpd in 2025, up from 10.75 

million bpd in 2010, and then fall to 11.21 million bpd 

in 2035. The EIA’s estimates for 2013 are much more 

optimistic about African oil, with production in 2035 

now projected to climb to 12.09 million bpd in 2035, 
31

and to 12.64 million bpd in 2040—the latter representing an 18.5 percent increase in daily production over 

the period 2010-2030.77

Source: BP Energy Outlook 2030, January 2012.

Table 3. Global Oil and Gas Production

(2010-2030).

Million Tons of Oil 

Equivalent 2010 2015 2020 2025 2030

North America 648.2 700.1 736.9 757.7 788.3

South/Central Asia 350 395.5 426.5 450.2 477.7

Europe and Asia 853.3 836.7 823.6 800.8 790.5

Middle East 1,184.6 1,285 1,379.8 1,540.5 1,646.4

Africa 478.2 475.1 512.4 504.9 497.6

Asia Pacific 399.4 397.1 383.5 344 311.3

Total Oil Production 1,913.7 4,089.5 4,262.7 4,398.1 4,511.8

North America 750.4 795.7 852.7 875.6 906.2

South/Central America 145.1 175.1 191.8 233.9 270.7

Europe and Eurasia 938.8 1,016.5 1,047.9 1,092.5 1,161.8

Middle East 414.6 579 655.9 741.8 821.3

Africa 188.1 213.4 257.2 298.6 356.8

Asia Pacific 433.9 545.6 706.9 770.1 811.4

Total Natural Gas 

Production 2,880.9 3,325.3 3,712.4 4,012.5 4,328.2
32

2010 2015 2025 2035

Middle East

OPEC 23.43 25.46 29.77 33.94

Non-OPEC 1.58 1.43 1.18 0.97

Subtotal 25.01 26.89 30.95 34.91

North America

United States 8.79 9.82 10.53 10.15

Canada 1.91 1.79 1.82 1.78

Mexico 2.98 2.65 1.58 1.68

Subtotal 13.68 14.267 13.93 13.61

Europe/Eurasia

Russia 10.14 10.04 11.06 12.16

OECD Europe 4.36 3.7 3.15 2.83

Other Europe and Eurasia 3.22 3.67 4.37 4.54

Subtotal 17.72 17.41 18.58 19.53

Africa

OPEC North Africa 3.89 3.62 3.37 3.37

OPEC West Africa 4.45 5.09 5.4 5.26

Non-OPEC Africa 2.41 2.4 2.68 2.68

Subtotal 10.75 11.11 11.45 11.21

Latin America

OPEC South America 2.29 2.13 1.92 1.72

Brazil 2.19 2.72 3.87 4.45

Other Central/South 

America 2.01 2.29 2.47 2.65

Subtotal 6.49 7.14 8.26 8.82

Table 4. International Oil Supply by Region, 

2010-2035 (in Millions of Barrels Per Day).
33

Note: Figures based on reference price for 2015, 2025, and 2035, 

which is between the “low oil price” and “high oil price” scenarios. 

Source: Annual Energy Outlook, Washington, DC: U.S. Energy Information Administration, June 2012, p. 195, as modified to reflect 

regions.

Table 4. International Oil Supply by Region, 

2010-2035 (in Millions of Barrels Per Day). (Cont.)

While these figures suggest only a modest increase 

in African oil and gas production until 2035, the author 

is encouraged about Africa’s energy future because a 

deeper analysis of EIA’s oil production estimates for 

Africa from 2010-2035 suggests that the continent’s oil 

production could be far higher than current forecasts. 

Table 4 indicates that non-OPEC Africa (i.e., Africa’s 

50 countries other than the four OPEC members, Algeria, Angola, Libya, and Nigeria) oil production in 2010 

was only 2.41 million bpd, or 22.4 percent of Africa’s 

total, and will only climb to 2.68 million bpd in 2035, 

or 23.9 percent of the predicted African total. Given 

2010 2015 2025 2035

East Asia/Australia

China 4.27 4.29 4.79 4.7

Japan 0.13 0.14 0.15 0.16

Other Asia 3.77 3.79 3.38 3.0

Australia/New Zealand 0.62 0.55 0.54 0.53

Subtotal 8.79 8.77 8.86 8.39

Total OPEC 34.06 36.3 40.46 44.19

Total Non-OPEC 48.38 49.28 51.57 52.28

Grand Total 82.44 85.58 92.03 96.47
34

Africa’s large number of sedimentary basins outside 

of its four OPEC member-states, several of which are 

proven hydrocarbon provinces, and given the extremely low level of exploration in the remaining 50 

African nations compared to these four “lions,” it appears likely that EIA’s estimates are highly conservative and mainly extrapolate from the present. 

Africa’s Competitive Landscape Becomes 

More Crowded—

Asian NOCs, Frontier Independents Join 

Traditional Supermajors.

What other evidence does the author have to corroborate his more optimistic views on future African 

oil and gas reserves? One leading indicator is that the 

competitive landscape for oil and gas exploration in 

Africa has become much more crowded over the last 

10 years with the addition of Asian NOCs, smaller international independents, the creation of new NOCs 

in some African countries, and the rise of regional energy companies from Africa such as Nigeria’s Oranto 

and South Africa’s Sasol. For decades, the Western 

“supermajors” such as the U.S. firm Chevron, the 

United Kingdom’s (UK) BP, and France’s Total explored onshore acreage across the continent, taking 

advantage of tax and royalty concessions. In the 1990s, 

they started investing in deepwater, which at the time 

was considered anything deeper than 1,000 feet. They 

have been joined, however, by Russian NOC Gazprom 

and Asian NOCs from China (CNPC, the China National Offshore Oil Corporation [CNOOC], the China 

Petroleum and Chemical Corporation [Sinopec], and 

Sinopec’s subsidiary Addax), India (ONGC), Indonesia (Pertamina), Korea (KNOC and its subsidiary 
35

Dana Petroleum), Malaysia (Petronas), and Thailand 

(PTTEP), plus a limited number of Russian and Asian 

independent firms. Most of the growing and vibrant 

group of small-to-medium-sized independent firms 

is from Europe and the United States. These include 

Anglo-Irish Tullow Oil, France’s Maurel et Prom and 

the U.S. firms, Anadarko and Kosmos. At least two 

dozen smaller independent E&P companies, some of 

which are privately held, have become active in Africa’s so-called frontier countries, often where there had 

been little past exploration activity or where such activity dated to the 1960s or 1970s. These smaller players, some of which also come from the United States, 

are important because they have a narrowly focused 

exploration-led business model (in contrast to supermajors, which manage across the value chain from 

exploration to retailing), usually have much higher 

risk tolerance than supermajors, and are willing to 

develop smaller hydrocarbon deposits that may be 

uneconomic to bigger companies.78 Examples of such 

firms include Canada’s Africa Oil, and Australia’s African Petroleum.

IV. GLOBALIZATION OF THE WORLD 

NATURAL GAS MARKET AND AFRICA’S 

ROLE IN IT

Up to this point, this monograph has focused 

mainly on oil production and reserves. However, 

natural gas will play a much bigger role in Africa’s 

energy future than it does now, so it merits the following separate discussion. 

At present, the global gas market is characterized 

by disparate regional markets. At present, the price of 

natural gas is much lower in the Atlantic Basin than it 
36

is in the Pacific Basin. At its lowest point in 2012, natural gas in the United States traded at around one-fifth 

of import prices in Europe and one-eighth of those in 

Japan.79 Major suppliers, including Russia and Norway, have historically maintained high natural gas 

prices by limiting pipeline volumes into Europe, and, 

in the case of Qatar, by restricting spot LNG volumes 

to Asian buyers. 

Recent events, particularly since 2010, however, 

are slowly creating a more competitive and interconnected global gas market. For example, more gas-related infrastructure development is enabling greater 

connectivity within and between regions, such as U.S. 

ports that can export LNG. Already, a limited amount 

of U.S. natural gas has been sold in Europe, and volumes could increase significantly if the U.S. Government grants more export licenses. The Panama Canal 

expansion, which will allow much larger PANAMAX 

LNG tankers, could also route U.S. LNG to Asian markets less expensively. Going forward, price differentials between regional gas markets will diminish as 

new supplier nations, many African, come on stream. 

LNG trade will become more competitive and contract terms will evolve, meaning that changes in one 

part of the world will be felt more quickly elsewhere.80

Some argue that once the Panama Canal is expanded, 

LNG supertankers will bring the Atlantic Basin and 

the Pacific Basin into one global market—much as 

the advent of oil supertankers fostered a global market in oil.81 In any event, West and Central African 

gas exports to Europe and Asia will help shrink the 

contract premiums significantly by 2020—providing a real boon to East Asian economies.82 Additional 

gas supplies coming online in East Africa starting 

after 2018 will further compress the Pacific-Atlantic 

price differential. 
37

The Present: Africa’s Natural Gas Production and 

Reserves Focused on North and West Africa.

African gas production reached about 203 billion cubic meters (bcm) in 2011, with production by 

Algeria, Egypt, and Nigeria, collectively, accounting 

for more than 88 percent of the continent’s total. Gas 

production in Africa since 2000 has been growing by 

about 4 percent per year.83 Africa accounted for 6.4 

percent of global natural gas production in 2010, but 

its share is expected to rise to 8.6 percent by 2035. As 

shown in Table 5, African gas production is projected 

to accelerate to 277 bcm in 2020 and 428 bcm in 2035.84

1990 2010 2015 2020 2025 2030 2035

OECD 881 1,178 1,239 1,328 1,360 1,395 1,446

Americas 643 816 893 970 993 1,026 1,067

Canada 109 160 165 171 169 174 188

Mexico 26 50 45 51 57 66 75

United States 507 604 679 747 765 784 800

Europe 211 304 267 250 238 226 215

Asia Oceania 28 58 80 107 129 143 164

Non-OECD 1,178 2,106 2,377 2,616 2,908 3,215 3,509

East Europe/Eurasia 831 842 893 968 1,057 1,136 1,204

Asia 130 420 502 548 607 684 775

China 15 95 134 175 217 564 318

India 13 51 54 62 72 84 97

Middle East 92 472 565 609 660 722 809

Table 5. Global Natural Gas Production by Region.
38

Source: World Energy Outlook 2012, IEA, Table 4.5.

Table 5. Global Natural Gas Production by Region. 

(Cont.)

As shown in Table 6, the largest natural gas producing countries in Africa in 2010, in descending order, were Algeria, Egypt, Nigeria, and Libya. Africa’s 

proven reserves of natural gas were estimated at 14 

trillion cubic meters (tcm) as of January 1, 2012, or 

about 7.5 percent of the world’s total. (Technically 

recoverable reserves of natural gas in Africa were estimated to be substantially higher, about 74 tcm, or 

almost 10 percent of the world’s total.) The countries 

with the biggest reserves were, in descending order, 

Nigeria, Algeria, Egypt, and Libya, with these four 

countries accounting for more than 92 percent of the 

continent’s total.85

1990 2010 2015 2020 2025 2030 2035

Africa 64 209 221 277 346 402 428

Algeria 43 80 83 105 123 140 147

Libya 6 17 16 20 26 32 37

Nigeria 4 33 43 58 71 87 94

Latin America 60 163 195 213 238 271 292

World 2,059 3,284 3,616 3,943 4,268 4,610 4,955
39

*Note: 2011 production figures (bcm) for certain countries available as follows: Algeria (78.0), Egypt (61.3), Libya (4.1), Nigeria 

(39.9), and other Africa (19.4). Source: BP Statistical Review of 

World Energy, June 2012.

Source: “National Gas in Africa: The Frontiers of the Golden 

Age,” Ernst & Young.

Table 6. African Natural Gas Production 

by Country (in Billions of Cubic Meters).

Country Reserves at

January 1, 2012

2010

Demand

2010

Production

Algeria 4,452 28.5 83.7

Angola 307 0.7 0

Benin 1 0 0

Cameroon 134 * *

Congo (Brazzaville) 90 0.9 0.9

Congo-Kinshasa 1 0 0

Egypt 2,162 45.6 60.6*

Equatorial Guinea 36 1.6 6.7

Ethiopia 25 0 0

Gabon 28 0.1 0.1

Ghana 22 0.1 0

Cote d'Ivoire 28 1.6 1.6

Libya 1,478 6.8 16.6*

Mauritania 28 0 0

Morocco 1 0.6 0.1

Mozambique 126 0.1 3.1

Namibia 62 0 0

Nigeria 5,053 4.9 28.7*

Rwanda 56 0 0

Senegal 0 * *

Somalia 6 0 0

South Africa 0 4 1

Sudan 84 0 0

Tanzania 6 0.8 0.8

Tunisia 64 3.2 2

Total 14,264 99.5 206.6
40

Historically, North Africa was the primary source 

of the continent’s natural gas exports. Algeria has 

long been a major player in global gas markets and 

has been the second-largest gas supplier to Europe 

after Russia. Libya’s natural gas is still relatively underdeveloped compared to oil, but the country is also 

an important supplier to Europe via the Greenstream 

pipeline to Italy.86 Recent growth in Africa’s natural 

gas supplies has come from West Africa through the 

huge associated gas developments that have accompanied an offshore oil boom led by Nigeria and Angola.87 Additionally, West Africa, aided by the World 

Bank’s Flaring Reduction Initiative, has become a focal point for capturing natural gas for export as LNG 

instead of being flared. While West Africa’s growth 

in natural gas will continue as flaring is reduced and 

local gas infrastructure is developed, the big future for 

African gas lies in the massive offshore gas discoveries 

in East Africa, particularly in Mozambique and Tanzania.88 Over time, the relative share of Africa’s “big 

four” suppliers will decline as natural gas production 

in other countries such as Mozambique and Tanzania, 

comes online and as their reserves become reclassified 

as “proven.”

East Africa and East Asia: A New “Golden Age” 

for Global Trade in Natural Gas?

Interest in the recent, large discoveries of natural 

gas in East Africa has been boosted by their convenient 

geographical position for LNG exports to Asian markets.89 The Asian appetite for East African natural gas 

is also understandable because, as one analyst put it, 

“It’s very important for Asian customers to secure gas 
41

free of the Strait of Hormuz risk.”90 Some analysts believe that final investment decisions to develop these 

East African gas reserves will not be reached, however, “without some long-term contracts attached, at 

least covering half or two-thirds of production.”91

The ease of access to Asian markets and a breakeven point that is substantially lower than rival Australia could help East Africa natural gas exports, particularly from Mozambique and Tanzania, according 

to consultant Wood Mackenzie.92 The firm estimation 

as of August 2012 is that 100 trillion cubic feet (tcf) 

of gas has been discovered in Mozambique and Tanzania to date—enough for 16 LNG “trains” (as liquefaction facilities are called)—and that yet-to-be-found 

reserves were as much as 80 tcf in Mozambique and 15 

tcf in Tanzania.93 (The average discovery size in Tanzania has been much smaller, around 2 tcf, compared to 

Mozambique, which is over 7 tcf. Discoveries in Tanzania are also more spread out, so developing them 

will be more expensive than those in Mozambique because additional infrastructure will be required;94 100 

tcf is enough to meet U.S. demand for 4 years.)95

Future Wild Card: Africa’s Unconventional 

Gas Supplies.

Over the longer term, Africa’s unconventional natural gas could also add substantially to the continent’s 

potential supply.96 In South Africa, the government 

recently lifted the moratorium on exploration and extraction of shale gas identified in three formations in 

the Karoo Basin.97 Relatively new, “unconventional” 

supplies of natural gas in several African countries—

including shale gas, tight gas, and coal-bed methane 

(also known as coal seam gas)—could add significant 
42

new supplies to the world’s energy markets.98 One 

analyst wrote that:

So far, shale and other unconventional gas searches in 

Africa have been focused mostly in South Africa, but 

there is evidence of coalbed methane deposits in West 

Africa and some tight gas sands along West Africa’s 

coast. Not without its environmental controversies, 

[Italian oil major] ENI’s planned launch of a pilot 

project with an estimated 2.5 billion barrels of recoverable oil sands in the Republic of Congo, is the clearest 

sign yet that Africa north of South Africa and south 

of the Sahara may have more robust unconventional 

gas prospects.99

Tables 7 and 8 show, respectively, current and 

future planned LNG facilities in Africa, and current 

LNG export facilities under construction worldwide. 

The fact that there are far more planned African LNG 

facilities than current production facilities is consistent 

with rising expectations for Africa as a global supplier 

of natural gas.

Country Project Start* Capacity Operator

Existing/Operating

Algeria Arzew (3 trains) 1964 1.1 Sonatrach

Skikda (4 trains) 1972 7.6 Sonatrach

Bethioua (12 trains) 1978 16.5 Sonatrach

Egypt Damietta (1 train) 2005 5.0 ENI

ELNG (2 trains) 2005 7.2 BG Group

Libya Marsa El Brega (2 trains) 1971 3.2 Sirte Oil

Nigeria NLNG (6 trains) 1999 22.2 NNPC

Equatorial Guinea Puna Eur (1 train) 2007 3.7 Marathon

Angola Angola LNG (1 train) 2013 5.2 Chevron

Table 7. Current African LNG Production Capacity.
43

*For existing projects, start date is date for first train; for 

planned/possible projects, start dates are nominal and subject to 

delay/cancellation.

Source: “Natural Gas in Africa: The Frontiers of the Golden 

Age,” Ernst & Young, 2012, p. 14.

Table 7. Current African LNG Production Capacity. 

(Cont.)

Country Project Start* Capacity Operator

Planned/Possible

Algeria Arzew GL 3Z 2013 4.7 Sonatrach

Skikda LNG 2013 4.5 Sonatrach

Libya Marsa El Brega T3 2013 2.6 Sirte Oil

Nigeria Progress FLNG 2017 1.5 NNPC

Cameroon Kribi LNG 2018 3.5 GDF Suez

Egypt Damietta T2 2018 4.8 ENI

Equatorial Guinea Punta Eur T2 2018 4.4 Marathon

Mozambique Mozambique T2 2018 5.0 Anadarko

Nigeria Brass LNG T1 2018 5.0 NNPC

Tanzania Tanzania LNG T1 2018 6.6 BG Group

Mozambique Mozambique T2 2019 5.0 Anadarko

Nigeria Brass LNG T2 2019 5.0 NNPC

NLNG T7 2019 5.0 NNPC

NLNG T8 2020 8.5 NNPC

OK LNG 2020 12.6 NNPC

Mozambique Mamba 2020 10.0 ENI
44

Notes: *coal-bed methane based; **floating LNG project.

Source: World Energy Outlook 2012, International Energy Agency, 

Table 4.7.

Table 8. LNG Export Projects Under Construction 

Worldwide (July 2012).

V. IS AFRICA STILL RELEVANT TO U.S. 

ENERGY SECURITY?

It may seem provocative to ask the question, “Is 

Africa still relevant to U.S. energy security?” but it is 

a strategic question that must be posed. The short answer is that Africa is still of major importance to U.S. 

energy security, but that past projections of U.S. oil 

and gas imports from Africa are proving far too high. 

Country Project Start-up Mt/Y Operator

Algeria Skikda new train end-2012 4.5 Sonatrach

Gasi Touil LNG 2013 4.7 Sonatrach

Angola Angola LNG 2013 5.2 Chevron

Australia Gorgon LNG 2014-15 15.0 Chevron

Queensland Curtis* 2014-15 8.5 BG

Gladstone* 2015-16 7.8 Santos

Australia Pacific ** 2015 6.1 ConocoPhillips

Wheatstone 2016-17 8.9 Chevron

Prelude** 2017 3.6 Shell

Ichthys 2017-18 8.4 Inpex

Indonesia Donggi Senoro 2014 2.0 Mitsubishi

Papua New Guinea PNG LNG 2014-15 6.6 ExxonMobil

Total 79.7
45

Africa had provided up to 22 percent of U.S. oil imports in recent years, and the countries of the Gulf of 

Guinea alone had been projected by the U.S. National 

Intelligence Council to be the source of 25 percent of 

U.S. oil imports by 2015.100 The new reality, however, 

is that the United States has been so successful in shale 

exploration and production in the last several years 

that it has been dramatically reducing its oil and gas 

imports from Africa, with 2012 U.S. oil imports from 

Africa being only 40 percent of their peak in 2007. Table 9 shows the long-term trend toward declining U.S. 

oil imports from Africa, which peaked in 2007.

Source: U.S. imports by country of origin, available from 

www.eia.gov.

Table 9. U.S. Imports of Oil by African Country 

of Origin (in Thousands of Barrels).

One reason for declining U.S. oil imports from Africa is that there has been a substitution in the U.S. 

import mix from African oil to oil produced in the 

Americas, including South America, Mexico, and CanDate Algeria Angola Libya Nigeria CongoBrazzaville

 CongoKinshasaEquatorial

Guinea Gabon Ghana IvoryCoast Total

2003 40,992 132,349 303,617 9,755 698 21,452 47,670 1,368 557,901

2004 78,719 112,018 6,724 394,560 2,918 5,101 2,212 52,061 1,840 678,153

2005 83,359 166,404 15,934 393,038 9,216 688 24,734 46,515 7,238 747,126

2006 131,981 187,325 23,949 378,670 9,753 20,894 21,773 1,630 775,975

2007 161,770 181,813 30,794 395,554 23,123 473 20,070 22,897 166 836,660

2008 114,112 184,460 24,791 337,359 24,673 27,159 21,268 630 734,452

2009 102,559 163,604 22,354 283,091 23500 3,412 32,310 22,926 947 654,703

2010 119,579 139,736 15,608 358,924 25,694 3,225 18,225 17,022 3,130 701,143

2011 64,816 122,210 3,328 280,079 19,192 3,999 6,934 12,532 2,954 1,303 517,347

2012 43,891 80,945 20,358 148,353 10,710 137 15,100 15,462 150 1,394 336,500
46

ada. Most importantly, however, there has also been 

a sharp absolute decline in U.S. oil imports from all 

source countries, primarily due to increased domestic 

production of nonconventional fuels, including shale 

oil and gas. The Washington Post analyzed this shift in 

oil imports in a January 2013 article, which stated that 

U.S. east coast refineries continued to import mainly 

African oil,101 but that refineries in the Midwest were 

stopping West African imports:

Over the past few years, U.S. refineries in the Midwest 

and elsewhere have spent billions upgrading their 

facilities in order to be able to process heavy, sour 

crude—the stuff that comes from the tar sands of Canada, or from Venezuela and Mexico. In order to recoup 

their investment, those refineries are likely to continue 

importing heavy oil from those three countries in the 

years ahead. By contrast, the light, sweet crude that’s 

now pouring out of shale formations in North Dakota 

and Texas will mainly displace oil from Africa: Since 

July 2010, the U.S. has cut its Nigerian imports by half, 

from more than 1 million barrels a day, to 543,000 as of 

October 2012, the most recent data available through 

the EIA. Imports from Angola have dipped below 

200,000 daily barrels, from an average of 513,000 

in 2008. . . . By the second quarter of [2013], we will 

stop importing West African light, sweet crude into 

the Gulf.102

As shown in Table 10, there were only three African nations among the top 15 source countries for 

U.S. oil imports during the period January-November 

2012: Nigeria (#5), Algeria (#10), and Angola (#11). 

These three countries cumulatively accounted for 

only 8 percent of U.S. imports. The United States imported about 40 percent less from Nigeria in 2012 than 

in 2011.103 For the 9 years to 2011, the United States 

imported between 9 and 11 percent of its crude oil 
47

from Nigeria; in the first half of 2012, this figure fell 

to 5 percent.104 U.S. natural gas imports have mainly 

been coming from Trinidad and Tobago, Qatar, and 

Algeria. Chevron has been forced to look at non-U.S. 

buyers, many in Europe, for its new natural gas production in Angola. 

Source: EIA, February 1, 2013, p. 4, available from www.eia.gov/

petroleum/imports/companylevel/.

Table 10. Total Imports of Petroleum into the

United States by Top 15 Source Countries

from January to November 2012.

By Region Thousand 

Barrels/Day

Percent of Total 

Imports By Country Thousand Barrels/Day

North America

Canada 2,938 0.26 Canada 2,938

Mexico 1,032 0.09 Saudi Arabia 1,390

Venezuela 939

Middle East Mexico 1,032

Saudi Arabia 1,390 0.12 Nigeria 459

Iraq 475 0.04 Iraq 475

Kuwait 313 0.03 Colombia 436

Africa Russia 473

Nigeria 459 0.04 Kuwait 313

Alergia 248 0.02 Alergia 248

Angola 243 0.02 Angola 243

Latin America Equador 180

Venezuela 939 0.08 United Kingdom 156

Colombia 436 0.04 Brazil 237

Ecuador 180 0.02 Norway 79

Brazil 237 0.02

Europe

Russia 473 0.07

United Kingdom 156 0.01

Norway 79 0.01
48

U.S. imports of African oil and gas are likely to decline further in the coming years as well. The International Energy Agency (IEA) predicts that oil production in the United States will peak in 2020 at 11.1 million 

barrels a day, with U.S. oil imports falling within the 

next decade to four million bpd from the current rate of 

10 million bpd. The U.S. Energy Information Administration (EIA) predicts that there will be only modest growth in demand for energy in the United States 

over the next 25 years, with an annual rate of growth 

in annual energy consumption of only 0.3 percent 

from 2010 to 2035. The United States is not projected 

to return to the levels of energy demand growth experienced in the 20 years prior to the 2008-09 recession 

because of more moderate projected economic growth 

and population growth, coupled with increasing levels of energy efficiency, according to ExxonMobil.105

Around 2030, North America is forecast to become 

a net oil exporter106—an outcome that also means 

the United States will enjoy an order of magnitude 

greater energy security in 20 years than it does at present, and will have little dependence on Africa for its 

energy needs.107

Despite declining U.S. oil and gas imports, Africa 

is still of major importance to U.S. energy security—

indeed to U.S. national security—for several reasons. 

First, although the United States will become significantly more energy independent in the years to come, 

it is still energy insecure for now, and Africa is thus 

still critical to a diverse supply of oil to the United 

States. Second, most of our Western allies, including 

Europe and Japan, will remain energy insecure for the 

foreseeable future, and will increasingly—not decreasingly—depend on oil and gas from Africa. Europe, for 

example, faced with declining oil and gas production 
49

in the North Sea and the unpredictability of Russia 

as an energy supplier, has increased its dependence 

on Africa, particularly on Algeria, Angola, Libya, and 

Nigeria for oil, and on Algeria and Libya for natural 

gas.108 Third, the commercial stakes for U.S. investors 

in African oil and gas are already enormous and growing rapidly. U.S. strength, and ultimately national security, depends on a strong economic foundation that 

creates jobs and wealth through exports and successful foreign investment, including to Africa. 

Table 11, a product of the author’s country-bycountry research found in Appendix 1, is a comprehensive but not exhaustive listing of current oil and 

gas exploration and production in Africa by U.S. companies. American firms have upstream activities in at 

least 22 countries on the continent, sometimes as the 

top first or second IOC in production. All but three of 

the 22 countries where U.S. firms are active in Africa 

are littoral or island nations. With the exception of the 

North African nations of Algeria, Libya, and Egypt, 

the large majority of active licenses held by U.S. firms 

involve offshore blocks, often deepwater. Outside 

of North Africa, sub-Saharan African countries with 

major U.S. oil and gas upstream investments include 

Nigeria, Angola, Equatorial Guinea, Chad, Ghana, 

and Mozambique. Other sub-Saharan countries with 

important U.S. upstream investments include Cameroon, Congo, Gabon, Kenya, Liberia, Madagascar, Morocco, Sierra Leone, South Africa, and Tanzania. 
50

Algeria** ConocoPhillips sold its Algerian operations to Indonesia’s NOC Pertamina in December 2012

Anadarko Largest foreign producer with 500,000 bpdHess Gassi El Agreb Redevelopment Project—investing to boost production in three long-standing oil fields

Angola Chevron Blocks O (Cabinda),2, 14. Soyo 5.2 Mmt/y LNG train. 434,000 operated bpd (36.4 percent share)

ExxonMobil 394,300 operated bpd; Block 17 (20 percent share)Marathon 10 percent interest in Blocks 31 and 32.ConocoPhillips 30 percent operator interests in two deepwater offshore Blocks 36 and 37.Cobalt International Operator rights to Angola’s offshore blocks nearshore 9, and deepwater 20 and 21.

Cameroon Kosmos 100 percent operated Ndian River Block and Fako Block

Murphy Oil Operator interests in three offshore blocks, 100 percent in Mer Profonde Nord and 50 percent in Mer Profonde 

Sud and 50 percent in Ndian River. 

Noble Energy 50 percent operator interests in the offshore YoYo mining concession and Tilapia exploration block.ExxonMobil/Chevron Chad-Cameroon Pipeline one of the largest U.S. investments in sub-Saharan Africa, majority interest held by 

ExxonMobil and Chevron. 

Chad ExxonMobil (40 percent)/Chevron 

(25 percent)

Production peaked at 126,200 barrels per day in 2010, and averaged 115,000 bpd in 2011. Exporting oil via 1,000-km pipeline to Cameroon’s Kribi port.

ERHC 100 percent shares in three blocks in 2011,BDS 2008, Chari Ouest III, and Manga

Comoros GX Technologies Seismic studies of part of Comoros’ territorial waters (probably only contractor, not investor)Congo (Brazzaville) Chevron Deepwater Moho-Bilondo Field, 31.5 percent, non-operator share

Murphy Oil Operator of offshore blocks, Mer Profonde Nord (100 percent share) and Mer Profonde Sud (50 percent share)ExxonMobil 30 percent, non-operator share in the deepwater Mer Tres Profonde SudChevron In joint Angola-Congo Lianzi cross-border oil field, with tie-back to BBLT platform in Angola’s Block 14

Table 11. Investment by U.S. Energy Companies

in Upstream Assets in Africa.
51

Cote d’Ivoire PanAtlantic (formerly Vanco Non-operator in Block CI-401 (28.34 percent), block CI-524 (30 percent)The Democratic Republic of the Congo (DRC)

EnerGulf Operator of the Lotshi Block in the onshore salt Coastal BasinChevron 17.72 percent, non-operator share in 12 onshore and offshore fields south of Angola’s Cabinda and north of 

Angola’s Soyo

Egypt Apache Largest producer of liquid hydrocarbons and natural gas in Western Desert, third largest in Egypt. In 2011, 

produced daily 217,000 bpd of crude oil and 865 mcf of natural gas (including joint venture partner-shares).

Equatorial Guinea ExxonMobil 71.25 percent interest in Block B

Hess 80.75 percent operator interest in the Ceiba FieldNoble Energy 38 percent operator of block I, including the 120,000 bpd Aseng oil field, and block O (45 percent operator), 

including the Alen gas-condensate field

Marathon Oil 63 percent production sharing contract (PSC) for block A-12 offshore Bioko 60 percent interest in an LNG 

facility on Bioko Island and 40 percent 

PanAtlantic 80 percent operator Block K—Corisco Deep in Rio Muni, partial share of Block W, Block EG-02 offshore Bioko 

Island

Brenham Oil & Gas (subsidiary of American International Industries)

15 percent participating interest for Block Y - offshore Rio Muni

Murphy Oil Operator Block W, offshore Rio Muni; in negotiations with government about acquiring interests in offshore 

Blocks J-14, J-15, K-14 and K-15

Ethiopia Marathon 20 percent, non-operator share in license in Turkana Rift BasinGabon VAALCO energy 50 percent operator in onshore Mutamba-Itoru exploration license

Marathon 21.25 percent, non-operator in offshore Diaba license G4-223; 28.1 percent interests in exploration acreage in 

the Etame Marine

Harvest Natural Resources 66.67 percent operator interest in Dussafu Marin BlockCobalt International Diaba Block (share, operator status unclear)CAMAC energy 100 percent operator interests in two offshore blocks: A2 and A5

Table 11. Investment by U.S. Energy Companies

in Upstream Assets in Africa. (Cont.)
52

Ghana Kosmos Energy 30.87 percent operator of Deepwater West Cape Three Points block. 18 percent non-operator in Deepwater 

Tano Basin. 

Anadarko 30.87 percent non-operator of Deepwater West Cape Three Points block. 18 percent non-operator in Deepwater 

Tano Basin. 

Hess 47.22 percent operator interest in Deepwater Tano/Cape Three PointsPanAtlantic 28.34 percent, non-operator interest in Cape Three Points Deepwater blockLushann International Lushann-Eternit Energy has 55 percent share in Saltpond Field, whose current production is about 600 bpd

Guinea Hyperdynamics Holds one of the largest offshore exploration acreage positions in West AfricaKenya Marathon 50 percent interest in Block 9 and a 15 percent interest in Block 12A

ERHC Block 11A in northwestern KenyaApache 50 percent operator in offshore Block L8Pancontinental 15 percent, non-operator Mbawa-1 exploration wellAnadarko 50 percent operator of Blocks L5, L7, L11A, L11B and L12CAMAC Energy 100 percent operator of Blocks L1B, L16, L27 and L28

Liberia Chevron Acquired three offshore blocks, LB-11, LB-12, and LB-14, in which it currently has a 45 percent operator 

interest

Anadarko 47.5 percent operator shares in Blocks LB-15, LB-16, and LB-17ExxonMobil 80 percent operator share offshore in Block LB-13

 Libya ConocoPhillips (16.33 percent), 

Hess (8.13 percent), and Marathon (16.33 percent)

In the Sirte Basin

Hess 100 percent operator of Area 54 offshore in Sirte BasinOccidental Petroleum Unknown share of Zueitina Field in Sirte Basin

Table 11. Investment by U.S. Energy Companies

in Upstream Assets in Africa. (Cont.)
53

Madagascar Madagascar Oil 100 percent of Blocks 3104-3107; Steam Flood Pilot project at Tsimiroro; 40 percent non-operator of Block 

3102 (Bemolanga)

ExxonMobil 70 percent interest in the offshore Ampasindava and Ambilobe Blocks in the northwest, and a 50 percent 

interest in the west-central offshore Majunga Block

MAREX 10 percent, non-operator interest in Deepwater Belo Profond 

Mauritania Kosmos 90 percent operator interest in three offshore blocksMorocco Chevron 75 percent of three offshore areas: Cap Rhir Deep, Cap Cantin Deep, and Cap Walidia Deep

Kosmos Operator shares in four offshore blocks, three in the Agadir Basin, and the fourth in the Aaoun Basin. 56.25 

percent participating interest in Foum Assaka Block, 75 percent interest in Essaouira Block

Plains Exploration and Production 52 percent operator interest in the Mazagan permit

Mozambique Anadarko Discovered natural gas at its offshore Windjammer well in the Rovuma Basin, followed by a total of 10 

successful exploration/appraisal wells also in the offshore block, “Area 1.” Lead operator (35.7 percent) of Rovuma Onshore on the Tanzanian land border adjacent to the Indian Ocean

Namibia EnerGulf Resources Exploring for oil and gas offshore

Duma Energy, Frontier Resources, and HydroCarb

Have encountered promising signs of hydrocarbons in the Owambo (Etosha) Basin. Frontier Resources has Blocks 1717 and 1817

Nigeria** ConocoPhillips sold its Nigerian operations to Nigeria’s Oando in December 2012

ExxonMobilChevronCAMAC (Exp. of several smaller U.S. independents in Nigeria)

ExxonMobil is 2nd largest oil producer in Nigeria. Erha North offshore project. 

Chevron is 3rd largest oil producer in Nigeria; 40 percent interest in 13 concessions with NNPC (NOC), and 18 

to 100 percent shares in 10 deepwater blocks. Major shareholder, operator of Escravos Gasto-Liquids facility and West African Gas Pipeline (WASP). CAMAC has an interest in a PSC for OML 120 with operator ENI of Italy. 

Senegal Fortesa 70 percent operator of Gadiaga Field; also has a license to explore the Tamna (Zone G) onshore block

Table 11. Investment by U.S. Energy Companies

in Upstream Assets in Africa. (Cont.)
54

Sierra Leone Anadarko Recent discoveries, including 4 wells successfully drilled

Kosmos Block 4A Chevron/Noble Energy Blocks 8a and 8bPanAtlantic 21 percent, non-operator in block in SL-5-11

South Africa Anadarko Exploration in Orange Basin

ExxonMobil 75 percent operator interest in exploration rights in the Tugela south and three other offshore blocksChevron Seek unconventional exploration opportunities in Karoo Basin

Tanzania ExxonMobil 35 percent, non-operator interest in Block 2Zambia Frontier Resources Exploration Block 34

Table 11. Investment by U.S. Energy Companies

in Upstream Assets in Africa. (Cont.)

Source: Internet Research by author, primarily from January-April 2013. See country profiles for more details. 
55

Aside from exploration and production, commercial opportunities for future U.S. trade and investment 

in Africa’s energy sector are extraordinary. IEA expects that almost $2.1 trillion will need to be invested 

in African oil and natural gas supply infrastructure 

over the period 2010-35—an average of more than 

$83 billion per year and more than will be invested 

in the Middle East, Latin America, or Asia over the 

same period.109 One author predicted in 2009 that just 

the gross deepwater capital expenditure in West Africa alone between 2008 and 2015 would exceed that 

spent in Latin America, the Gulf of Mexico, the North 

Atlantic and Asia-Pacific.110 Over the next five years 

alone, at least $230 billion will be required in Africa 

to develop LNG capacity and $22.6 billion to develop 

gas-to-power projects.111 Much of this will be invested 

by U.S. operators including, for example, Chevron in 

Angola and Anadarko in Mozambique. U.S. oil services providers and industrial firms producing oil, gas, 

and power-sector equipment have traditionally been 

internationally competitive and, as such, Africa is a 

future bonanza that cannot be ignored.112

In the text above, the author asserts that, for now, Africa will remain important to U.S. “energy security,” 

but that its importance will decline over the next 20 

years due to greater oil and gas production in the 

United States and the rest of North America. What exactly do we mean here by “energy security”? Energy 

security has three components: reliability (or regular, 

uninterrupted access to energy), affordability, and environmental friendliness. At present, the United States 

enjoys a relatively high and improving level of energy 

security primarily related to reliability of supply.1

The U.S. energy security is high not just because of 

booming shale oil and gas production, however, but 

also due to better mechanisms for dealing with sup-
56

ply challenges than in the past. These include the existence of a Strategic Petroleum Reserve started in 1975,2

and the International Energy Agency created in 1994 

to make possible timely collective responses to politically inspired disruptions in oil supplies. 

U.S. energy security has also been enhanced by

greater oil and gas imports from Canada, which is tied 

by pipeline to the U.S. energy economy.3 The United 

States is also less vulnerable to disruptions in the 

global oil market in part because U.S. refiners have 

more refining capacity that is able to refine lowerquality, heavier crude, which means that they are not 

stuck with having to purchase higher-grade, lighter 

crude. (In contrast, the Chinese economy is structured 

around its crude oil production in Daqing, which 

produces relatively light, sweet, waxy crude. Chinese 

refineries are equipped to process this kind of crude 

and, since they have not converted many of their refineries to process heavier crude, they import significant 

amounts of light crudes into China.)4 

Although the United States enjoys a relatively high

level of energy security in 2013, plenty of risk remains. 

First, although U.S. dependence on oil imports is declining, our security vulnerabilities do not arise solely 

from the amount of oil we import. Affordability is 

also an issue.5

 Oil is a strategic commodity traded on 

a global market. Therefore, supply disruptions cause 

spikes in price, which then increase dramatically the 

U.S. import bill for oil, even though oil is still available to U.S. buyers. Second, for the United States, oil’s 

strategic status does not stem from its use for electricity because only 1 percent of U.S electricity is generated from oil (other than in the strategic location of 

Hawaii, where the U.S. Pacific Fleet is headquartered, 

and where the large majority of electricity in that state 

is generated from imported fuel oil, about 70 percent 

of it from East Asia and Australia).6

 Instead, oil’s strategic status stems from its virtual monopoly over the 

U.S. transportation fuel. In the United States, 98 percent of transportation energy is petroleum-based.7
57

How can the United States reduce its dependence 

on petroleum-based transportation energy? One way 

the United States has already reduced this dependence 

is to add more ethanol to our fuel mix. Another solution is to produce more vehicles that run on natural 

gas, thereby helping to monetize the price difference 

that exists today between oil and natural gas. This 

is already happening for U.S. truck fleets, especially 

those that constantly run the same routes because fueling stations are profitable to construct. Eighteen-wheel 

trucks running on natural gas save well over $150,000 

in fuel costs over their 6-year expected life. Oil industry veteran T. Boone Pickens said in 2012 that converting U.S. truck fleets to natural gas could “knock out” 

70 percent of U.S. imports from OPEC countries, and 

recalled that it took 6 years for the U.S. truck fleet to 

convert from gasoline to diesel in the 1970s.8

 Yet another option is to accelerate the move already started 

in the auto market toward hybrid gas-electric and 

all-electric vehicles. On a per-mile basis, electricity is 

much less expensive than oil.9

Fortunately, U.S. demand for oil is already flattening off—and U.S. energy security already increasing—

in significant part because we are already improving 

efficiencies of our transportation fleet. Over time, this 

push toward greater fuel mileage will also be helped 

immensely by the Barack Obama administration’s 

agreement in 2011 with 13 large automakers to increase fuel economy to 54.5 miles per gallon for cars 

and light trucks by 2025.10 By around 2020, the United 

States will start to see the impact of the latest CAFE 

fuel-efficiency measures in transport. The result will 

be a continued fall in U.S. oil imports, to the extent 

that North America becomes a net oil exporter around 

2030.11

This withdrawal of the United States as a major

buyer in the global energy market (ex-North America) 

will also accelerate the switch in direction of international oil trade towards Asia, from Africa and the Middle East. The next two sections of this monograph will 
58

focus on Africa’s importance to China as a source of 

energy, including how Beijing will likely build a bluewater navy whose core mission will include a presence in the Indian Ocean to protect oil and gas supply 

routes to its homeland.12

Endnotes - Text Box

1. The case can be made that unconventional oil and natural

gas have also increased, on net, the environmental component 

of energy security. While hydraulic fracking, for example, carries risks of water contamination, the greater use of natural gas 

for power generation has displaced the use of heavily pollution 

coal.

2. See en.wikipedia.org/wiki/Strategic_Petroleum_Reserve_

(United_States).

3. Carolyn Pumphrey, ed., The Energy and Security Nexus: A 

Strategic Dilemma, Carlisle, PA: Strategic Studies Institute, U.S. 

Army War College, November 2012, p. 26.

4. Ibid., pp. 28-29.

5. Ibid., p. 2.

6. “Responses to Frequently Asked Questions Concerning

Electricity Rates and Oil Prices,” Honolulu, HI: State of Hawaii 

Public Utilities Commission, August 2, 2012; and “Fuel Use in 

Hawaii,” available from www.heco.com.

7. Pumphrey, ed., The Energy and Security Nexus,” p. 55.

8. “Pickens says converting truck fleets to natural gas will 

‘knock out’ 70 percent of OPEC’s imports,” DC Velocity, June 

28, 2012.

9. Pumphrey, ed., The Energy and Security Nexus,” pp. 55, 

58.

10. “Obama Administration Finalizes Historic 54.5 MPG

Fuel Efficiency Standards,” Washington, DC: The White House, 

August 28, 2012.

11. World Energy Outlook 2012, Paris: International Energy 

Agency (IEA), 2012, pp. 1-2.

12. Ibid.

Box 1. What is Energy Security and 

How to Promote it in the United States?
59

VI. AFRICA AND CHINA’S ENERGY

SECURITY—AN INCREASINGLY IMPORTANT 

SOURCE OF DIVERSIFIED SUPPLY

Since the mid-1990s, Africa has played an increasingly strategic role in China’s energy security. China’s 

rapid economic development turned the country from 

a petroleum exporter to an importer by 1993—a significant milestone in its development, and an event 

that spurred China to adopt a new foreign policy in 

1995 emphasizing greater economic ties with Africa.113

In recent years, the quality and availability of Africa’s 

oil also became more important to Beijing as a way to 

offset declines in the North Sea and other light sweet 

crude producers that had previously met Chinese demand for crude and refined products.114 As of 2009, 

Africa accounted for a significant share of the international equity production portfolio for China’s “big 

three” oil companies: CNPC (40 percent), Sinopec (22.6 

percent), and CNOOC (45 percent).115 CNPC, the biggest of the three, also operates through its Great Wall 

Drilling subsidiary in eight African countries: Algeria, 

Chad, Kenya, Libya, Niger, Sudan, South Sudan, and 

Tunisia. 

In 2009, China became the second largest net oil 

importer in the world behind the United States, with 

net total oil imports reaching 5.5 million bpd in 2011, 

versus 8.7 million bpd for the United States.116 More 

than half of China’s crude oil is imported, and about 

33 percent of these imports came from Africa and 

47 percent from the Middle East in 2010. Africa is a 

critical part of China’s energy security diversification 

strategy, which seeks above all to reduce its dependence on Middle East oil. In December 2012, China 

overtook the United States as the world’s largest net 
60

importer of oil, a development that the Financial Times

predicted would: 

shake up the geopolitics of natural resources [since] 

the US has been the world’s largest net importer of 

oil since the mid-1970s, shaping Washington’s foreign 

policy towards energy-rich countries such as Saudi 

Arabia, Iraq and Venezuela.117

U.S. net oil imports dropped to 5.98 million bpd in 

December 2012, according to provisional figures from 

the EIA. In the same month, China’s net oil imports 

surged to 6.12 million bpd, according to Chinese customs. By 2020, China will import about 65 percent of 

its crude oil. 118 An increasingly large share of China’s 

imports will have to come from Africa.

Securing natural resources, most importantly oil 

and natural gas, is already Beijing’s top national security priority in Africa.119 While Africa’s strategic importance for U.S. energy security is in relative decline due 

to shale oil and gas discoveries in America, the continent’s importance continues to rise for China which, 

despite shale discoveries of its own, will increasingly 

depend on energy imports until well past 2040.120 The 

IEA predicts, for example, that global energy demand 

will grow by one-third over the period to 2035, with 

China, India, and the Middle East accounting for 60 

percent of the increase. Similarly, Table 12 predicts 

that energy demand in China will climb from 102 

quadrillion British thermal units (QBTUs) in 2010 to 

138 QBTUs in 2040 (and in India from 28 QBTUs in 

2010 to 61 QBTUs in 2040, in the Middle East from 30 

QBTUs in 2010 to 51 QBTUs). 
61

Source: “The Outlook for Energy: A View to 2040,” available 

from www.ExxonMobil.com, 2012, p. 49.

Table 12. World Energy Demand (2010-40).

As indicated in Table 13, China’s top three sources 

of oil in the world in 2010 were Saudi Arabia, Angola, 

and Iran, while its top three sources of oil in Africa 

were Angola, Sudan, and Libya.

Energy Demand

(Quadrillion BTUs) Percent Change Share of Total

Regions 2010 2025 2040 2010-25 2025-40 2010-40 2010 2025 2040

World 525 633 692 21 9 32 100 100 100

OECD 227 234 224 3 -4 -2 43 37 32

Non-OECD 298 400 469 34 17 57 57 63 68

Africa 29 44 62 55 39 115 5 7 9

Asia Pacific 205 267 301 30 12 47 39 42 43

China 102 132 138 29 4 35 19 21 20

India 28 45 61 62 37 122 5 7 9

Europe 81 82 78 2 -4 -3 15 13 11

European Union 73 73 69 0 6 -6 14 12 10

Latin America 26 36 45 39 24 73 5 6 7

Middle East 30 42 51 41 21 71 6 7 7

North America 113 118 112 4 -4 -1 22 19 16

United States 94 96 90 2 -6 -5 18 15 13

Russia/Caspian 42 43 43 4 -1 3 8 7 6
62

Source: FACTS Global Energy, 2010.

Table 13. China’s Oil Imports in 2010,

by Source Country

(in 1,000 Barrels Per Day).

Data from China’s General Administration of Customs showed that Angola had become China’s largest source of crude imports in April 2010, surpassing 

Saudi Arabia. As shown in Table 14, five of China’s 

top seven trading partners in Africa in 2010 were oil 

exporters: Angola, Nigeria, Libya, Algeria, and Congo 

(Brazzaville).121

Saudi Arabia 893

Angola 788

Iran 426

Oman 317

Russia 284

Sudan 252

Iraq 225

Kuwait 197

Kazakhstan 184

Brazil 151

Libya 148

Other 922
63

*Indicates country from which China purchased oil and

minerals.

Table 14: China’s Top Trade Partners 

in Africa in 2010 (in $ Billions).122

China’s strategy of using Africa to move away 

from the Middle East/Strait of Hormuz risk through 

diversification has not been without its own risks. 

Libya had accounted for 3.1 percent of Chinese imports in 2010, but Chinese oil imports from Libya were 

disrupted by civil war and the North Atlantic Treaty 

Organization (NATO) intervention in March 2011.123

The feud between Sudan and the recently independent South Sudan over oil pipeline fees also led to a 

multi-month cutoff in China’s significant oil imports 

from those two countries. This being said, there is no 

doubt that, overall, China will enjoy much greater diversification of oil-source countries within Africa in 

the coming years due to ongoing exploration and production in multiple countries—both by Chinese and 

non-Chinese firms. This will enable China to be less 

1. South Africa ($25.7) 11. Kenya ($1.7)

2. Angola ($24.8) 12. Tanzania ($1.5)

3. Nigeria ($ 7.8) 13. Ethiopia ($1.3)

4. Egypt ($ 7.0) 14. Mauritania ($1.2)

5. Libya ($ 6.6) 15. Gabon ($1.1)

6. Algeria ($ 5.2) 16. Tunisia ($1.1)

7. Congo ($ 3.5) 17. Equitorial 

Guinea

($1.1)

8. Morocco ($ 2.9) 18. Cameroon ($1.0)

9. Zambia ($ 2.9) 19. Chad ($0.8)

10. Ghana ($ 2.1) 20. Botswana ($0.4)
64

vulnerable to disruptions within Africa from, e.g., an 

oil industry strike in Nigeria, and to disruptions elsewhere, e.g., a conflict in the Middle East tied to Iran. 

China’s Success in Marginal or Politically Sensitive 

Oil Fields.

Up to now, China’s “oil diplomacy” in Africa has 

been most successful in niche markets such as Angola 

(due to corruption and to its $14 billion in infrastructure-for-oil deals),124 and in other African countries 

with fields that have been ignored as too marginal 

or politically sensitive by major Western companies. 

Countries where China has invested in marginal

fields include Nigeria, Chad, Congo, Niger, Gabon, 

Equatorial Guinea, and the DRC. In Niger, for example, China’s CNCP took over a license in 2003 from an 

ExxonMobil/Petronas joint venture in Agadem that 

was not renewed.125 Buttressing CNCP’s investment in 

Niger, the China-Africa Development Fund (CADF) 

has underwritten a 2,000-km pipeline to export oil via 

another pipeline originating in Chad.126 An example 

of a politically sensitive country is Sudan, where China’s “no strings attached” foreign policy supported 

Beijing’s oil diplomacy. In Sudan, both Chinese NOCs 

CNPC and Sinopec were able to take over projects 

from Western oil companies and ignore international 

sanctions. With the independence of South Sudan in 

July 2011, this new country became China’s second 

most important source of oil in Africa.127
65

The Absolute and Relative Scale of China’s 

Investment in Africa’s Upstream Oil and 

Gas Industry.

Do oil-for-infrastructure in Angola and sanctionsbusting in Sudan mean that the Chinese government’s 

oil diplomacy is assisting Chinese energy companies 

to unfairly edge out traditional Western majors and 

smaller independents in Africa? In June 2008 congressional testimony, two U.S. Deputy Assistant Secretaries of State for Africa and East Asia said “no”:

There are often exaggerated charges that Chinese 

firms’ activities or investment decisions are coordinated by the Chinese government as some sort of strategic gambit in the high-stakes game of global energy security. In reality, Chinese firms compete for profitable 

projects not only with more technically and politically 

savvy international firms, but also with each other.128

What do further analysis and the empirical data indicate? While Angola and Sudan may be exceptions, 

the author’s research suggests that the U.S. officials 

were correct in their testimony. The Chinese Ministry 

of Commerce has commercial counselors in 48 of its 

Embassies in Africa, and they undoubtedly engaged 

in commercial diplomacy to lobby host governments 

in support of their NOCs—bolstered by relatively frequent, high-level visits by Chinese government or party officials. It is no coincidence that in March 2013—a 

mere 4 months after assuming office—Chinese President Xi Jinping visited three African nations that are 

natural resource exporters: Congo (oil, with China 

as its biggest trading partner), Tanzania (an emerging natural gas exporter), and South Africa (a source 

of strategic metals and minerals).129 This commercial 
66

diplomacy in no way implies, however, that the activities or investment decisions by Chinese NOCs in 

Africa are “coordinated by the Chinese government.” 

In Angola, a Beijing-sponsored $14.5 billion oilfor-infrastructure deal and corruption may have 

facilitated the acquisition by Chinese NOCs of nonoperator shares in oil and gas blocks; in Sudan, Chinese and other Asian oil companies did purchase 

the assets of departing Western oil companies; and 

in Chad, diplomatic competition between Beijing 

and Taipei ironically encouraged oil sector investment by both the People’s Republic of China (PRC) 

and Taiwan.130 Despite these three, however, there 

are no other countries in Africa where Beijing’s foreign policy priorities appear to have had a clear, determining influence on the activities or decisions of 

Chinese NOCs.131

In any event, regardless of whether the Chinese 

government’s role has been more of advocacy or directive, Chinese oil companies are continuing to increase 

their investments in Africa rapidly, albeit from an initially modest base. Table 15, derived from the author’s 

detailed country-by-country research presented in 

Appendix 1, is a comprehensive, but not exhaustive, 

listing of Chinese investment in upstream oil and gas 

assets in Africa. This table outlines 20-plus countries 

where Chinese firms reportedly have an interest in 

exploration and production. A perusal of this chart 

reveals that Chinese firms have a significant presence 

in three major oil and gas producing countries—Algeria, Angola, and Nigeria—and in four smaller producers—Cameroon, Chad, Gabon, and Sudan. Chinese oil 

firms also made major investments in Uganda in 2012 

and Mozambique in 2013, only once as an operator 

(of one project in Uganda). The presence of Chinese 
67

oil companies in the remaining 11 African countries 

varies from as little as an office and rumored farmin to new projects to, at best, exploration and limited 

production in others. If one compares the narratives 

in each country synopsis that follows and examines 

the maps of explorations blocks on the continent, the 

same picture of Chinese oil companies remains: growing significantly, but still dwarfed by the investments 

by Western majors and independents. (At the same 

time, and as becomes apparent in reading through 

the country-by-country profiles, it is notable that Chinese firms in Africa do have a relatively greater number of oil exploration and production licenses than 

firms from other, non-African developing countries, 

including the other BRIC countries of Brazil, Russia, 

and India.) 
68

Country Chinese Companies Comments

Algeria CNOOC

CNOOC, along with partner Sonatrach and Thailand’s PTTEP, successfully discovered crude oil in September 2012 in the 4th and the 5th exploration wells in the Hassi Bir Rekaiz project.

CNPC

Acquired the exploration licenses for Blocks 102a /112 in the Chelif Basin in northern Algeria (75 percent operator; 25 percent Sonatrach), Block 350 the northwestern Oued Mya Basin in the north of the Sahara Desert (75 percent operator; 25 percent Sonatrach), and Block 438b, also in the Oued Mya Basin (100 percent)

Angola

CNOOC Non-operator shares in several offshore blocks.

Sinopec

Joint venture with China Sonangol known as Sonangol Sinopec International (SSI), which holds 50 percent participating interest in Block 18, operated by the UK’s BP. Equity production was 72,000 BOPD in 2010.

China Sonangol

Besides JV with Sinopec, most important assets are 27.5 percent share in Block 17/06 and 20 percent share in Block 32. Also has non-operator interests in six other oil blocks in Angola (3/05, 3/05A, 15/06, 18/06, 31, and onshore Cabinda Block North). 

Benin Sinopec (Addax 

subsidiary)

50 percent interest in Block 1.

Cameroon Sinopec (Addax 

subsidiary)

37.5 percent non-operator share in most prominent new field, Dissoni. Struck hydrocarbons in October 2012 estimated at 20 million barrels of oil and 200 bcf of natural gas in the Padouk-1X Permit in Rio del Rey Basin. Ngosso license area is in Rio del Rey Basin (60 percent operator). Iroko license area is located approximately 30 km offshore (100 percent operator). 40 percent operator interest in Lokele’s Mokoko Abana Field. 24.5 to 32.25 percent shares in eight fields in Lokele (2) and Rio del Ray (6) operated by Perenco. 

Sinopec

Bought 80 percent stake in Shell Oil’s Cameroon subsidiary in 2011; remaining 20 percent owned by NOC SNH. Purchase gave firm stakes in 12 offshore blocks in Cameroon.

Yang Chang Logone Development Holding

Acquired two blocks, Makary near Lake Chad, and Zina, about 20 km north of the Waza Park, in onshore northeast.

Table 15. Exploration and Production Activities of Chinese Energy 

Firms in Africa.
69

Central African Republic

CNPC

In collaboration with Sudanese partners, restarted oil exploration in 2011 in northeastern CAR. Identified four promising sub-basins: Bagara (between CAR, Sudan, and South Sudan), Doseo (between CAR and Chad), Salamat (CAR), and Doba/Bangor (Chad).

Chad CNPC

Bought shares in Block H, in whose Bongor Basin the company subsequently made several commercial discoveries starting in 2006. In 2007, signed agreement with Chadian Ministry of Petroleum for the establishment of a 60-40 joint venture, 20,000-bpd refinery in Ndjamena, which started production in 2011. Construction of 311-km pipeline from fields to new refinery completed in 2011.

Congo CNOOC Hired a ship to drill in its offshore block in 2013 1H.

Equatorial Guinea

CNOOC Block S. CNPC

70 percent operator interest in Block M in the Rio Muni Basin through Santa Isabel Petroleum subsidiary. 

Xuan Energy(Hong Kong)

Granted license in December 2012 as operator of newly created Block Y, offshore Rio Muni, with a 15 percent interest for Brenham Oil & Gas, a subsidiary of American International Industries.

Eritrea

Defba Oil Share Company, reportedly a joint venture between undisclosed Chinese company and Saudi-Bahraini Energy Alliance Company

Signed oil exploration agreements in 2008 for the two most northerly offshore blocks on the maritime border with Sudan—Bahri and Defnin. 

Ethiopia

Sinopec In 2007, the Ogaden rebel movement ONLF destroyed oil exploration facility outside Abole 

operated by Sinopec, killing 65 Ethiopians and nine Chinese. 

Petro-Trans(Hong Kong)

Malaysia’s Petronas sold out its shares to China’s Hong Kong-based PetroTrans in 2010, whose facilities were also threatened with attack from an Ogaden-based rebel movement in August 2011. Ethiopian government cancelled five PSAs for 10 blocks in July 2012, claiming PetroTrans had failed to raise promised financing for new investments.

Table 15. Exploration and Production Activities of Chinese Energy 

Firms in Africa. (Cont.)
70

Gabon

CNOOC 25 percent share of offshore Blocks BC9 and BCD10. Sinopec Continued work on “several exploration wells” in Block G4-188.Sinopec (Addax subsidiary)

Sinopec’s Addax subsidiary had five production sharing agreements, two as onshore operator of Maghena and Panthere NZE, with five producing fields, two discoveries, and one under development. 

Ghana Sinopec

In July 2012, won $750 million contract to develop Ghana’s National Gas Processing Project, which involves transporting and marketing associated gas from the Jubilee Field. The Chinese government offered financing and agreed to accept repayment in the form of a long-term oil supply contract. 

Guinea China Sonangol

Officials in earlier Transitional government had awarded offshore acreage. However, democratically elected government of President Alpha Conde said he wiill review oil agreements made by previous regimes. China Sonangol’s website does not list any oil and gas operations in Guinea, but does list a Conakry office. 

Kenya

CNOOC In 2010, plugged the Bhogal-1 exploration well on Block 9 in north-central Kenya after 

inconclusive results, returned its two licenses, and left the country.

Liberia CNPC 

(Hong Kong-listed arm, PetroChina)

Australia’s African Petroleum made new offshore oil discovery in February 2013 when drilled Bee Eater-1 well. The company is finalizing negotiations with PetroChina for an investment of up to 20 percent in offshore Block LB-09. 

Libya CNPC

Partial interest with Libya’s NOC in offshore Block 17-4 in the Pelagian Basin off the northwestern coast of Libya. Greatwall Drilling Company, a subsidiary, is also present in Libya Subsidiary.

Mauritania CNPC

In 2006, found hydrocarbons in offshore Block 20, for which it has 65 percent operator 

interest, with Australia’s Baraka Petroleum holding 35 percent. Onshore, exploration continues in the Taoudeni Basin, in central-eastern Mauritania.

Table 15. Exploration and Production Activities of Chinese Energy 

Firms in Africa. (Cont.)
71

Mozambique

CNPC Italy’s ENI reached an agreement in March 2013 to sell CNPC a 20 percent interest in offshore 

Area 4. 

Niger CNPC

In Agadem, took over in 2003 100 percent share in Block Bilma and an 80 percent share in Block Tenere, along with Canadian oil company, TG World (20 percent). 

Nigeria

 CNOOC 45 percent of Akpo Field (OML 130), operated by Total. 

38 percent of Stubb Creek (OPL 229). 

CNPC 4 blocks: 2 in Niger Delta, one onshore, the other offshore (OPL 298 and OPL 471), 2 in Chad 

Basin in Bomo Province in northern Nigeria (OPL 721 and OPL 732, the latter of which is a risk exploration block.

Sinopec Operatorship of NPDC’s OML 64 and 66. 

20 percent stake in the Usan Field. 

Sinopec (Addax subsidiary)

Onshore, 100 percent operator of OML 124.Offshore, 100 percent operator of OML 123, 126, 137; 72/5 percent operator of OPL 291, nonoperator of Okwok (12 percent share) and OPL 227 (40 percent share)Non-operator of Block 1 (42.37 percent share) in JDZ with Sao Tome and Principe

Sao Tome andPrincipe

Sinopec Operator in Block 2. Sinopec (Addax subsidiary)Sinoangol (not China Sonangol)

Operates Blocks 3 and 4 in JDZ with NigeriaApplying for exploration rights in Block 2. 

Sudan/South Sudan

CNCP

Shares in three consortia whose minority shareholder include Sudan NOC Sudapet and/or South Sudan NOC Nilepet. 

Sinopec

Sinopec (6 percent) and Egypt/Kuwait’s Tri-Ocean Energy (5 percent) are minority shareholders in one of the three consortia, Dar Petroleum (Petrodar), which is based in South Sudan.

Uganda CNOOC

In February 2012, Tullow farmed out part of interests to CNOOC and France’s Total, with each taking a one-third share in Blocks EA-1, EA-2, and the former EA-3, now known as the Kanywataba and Kingfisher licenses, with each as operator of one of these three blocks. 

Table 15. Exploration and Production Activities of Chinese Energy 

Firms in Africa. (Cont.)
72

Where does the disconnect between popular 

misperceptions in the mainstream press of large-scale 

Chinese investments of African equity oil come from? 

One reason may be an erroneous extrapolation from 

overall foreign trade and investment trends between 

China and Africa, which do, indeed, show an exponential growth in commercial ties over the last 30 

years. While this burgeoning economic relationship 

between Beijing and African capitals is real, it is diversified and not just concentrated in the energy sector. 

And while the absolute size of Chinese investment in 

African oil and gas assets is both growing significantly 

and likely part of a longer-term trend, one recent figure indicated that Chinese oil companies accounted 

for just 8 percent of the combined commercial value of 

all international oil company investments in Africa.132

Why is this figure so low? One reason is because Western oil companies had a head start of several decades, 

making their cumulative investment much larger 

than that of China. Another reason is that these Western firms are not standing still, but instead investing 

huge amounts of capital into Africa’s promising oil 

and gas sector, outweighing recent investments by 

Chinese NOCs.

At the same time, while the relative importance 

of Chinese NOCs in Africa may not be rising rapidly, 

the absolute amount of their investments certainly is. 

Chinese oil and gas multinationals have been actively 

investing in African assets via “farm-ins” of existing 

consortia, bids on licenses, and the outright acquisitions of smaller global independents.133 CNOOC, along 

with France’s Total, purchased in 2012 for $2.9 billion 

a farm-in of acreage in Uganda’s Lake Albert Rift Basin controlled by Anglo-Irish Tullow Oil. This TullowTotal-CNOOC partnership will spend between $10 
73

and $12 billion by 2017 to develop around 3.5 billion 

barrels of oil resources in Uganda and export most of 

this to international markets. For its part, CNPC spent 

about $2.5 billion to buy a 20 percent stake in the Usan 

Field in Nigeria (Block OML 138) in November 2012134

and $4.21 billion in March 2013 to farm-in to 20 percent of ENI of Italy’s offshore Mozambique Area 4 

gas fields. 

Table 15 also provides multiple, recent examples 

of successful Chinese NOC bids on licenses. For example, in December 2012, the government of Equatorial Guinea granted Hong Kong-registered Xuan 

Energy a license as operator of newly created Block 

Y, offshore Rio Muni. Two examples of Chinese acquisitions of smaller independents with African ties 

are Sinopec’s purchase in 2009 for $7.2 billion of Canada’s Addax Petroleum (which had assets in several 

African countries) and CNOOC’s $15 billion buy-out 

in early 2013 of Canada’s Nexen (which had assets in 

Nigeria including in the Usan Field).135 Sinopec is also 

rumored to be interested in buying some of the Gabon 

assets of France’s Maurel et Prom, which account for 

95 percent of the company’s production, or in making 

an outright acquisition of the company.136 Sinopec was 

also reported in February 2013 to be in talks with the 

UK’s Afren about buying about $1 billion in oil assets 

in Nigeria.137

Is China’s Investment in Africa’s Oil and 

Gas Sectors Good or Bad?

Is rising Chinese investment in the Africa’s oil and 

gas sectors good or bad? There certainly can be negatives from Chinese investment in Africa, such as questionable business practices that use bribery to undermine good governance, abusive labor practices that 
74

give preference to Chinese skilled and even unskilled 

labor, and lax compliance with international environmental norms and local laws. Another concern is the 

competitive advantage that Chinese companies have 

because they do not participate in the voluntary standards created by Western governments to foster improved governance, including environmental impacts 

and respect for human rights. Even for established oil 

producers like Nigeria, Angola, Equatorial Guinea, 

Gabon, and Congo (Brazzaville), there is a strong 

presumption that rent-seeking members of these governments have been corrupted by Chinese firms (and 

other Asian NOCs), which are not bound by OECD 

anti-corruption measures.138

Overall, however, the West should not be overly 

concerned about China’s investment in Africa’s energy sector. Why? For one, China’s three major oil firms 

are actually leaders among their national brethren in 

other sectors in modernizing their business practices. 

Even China Sonangol, a past poster child for corrupt Chinese business practices in Africa, appears to 

be making considerable effort to repair the damage 

of past alleged actions through, e.g., hiring Western 

CEO Alain Fanaie, the former head of infrastructure 

and commodities at France’s Credit Agricole,139 and 

making its website, which now prominently touts 

the firm’s work on corporate social responsibility, 

more transparent.140 China’s “big three” oil companies, while partially state-owned enterprises, are also 

traded on international exchanges, e.g., on the New 

York Stock Exchange as American Depositary Receipts (ADRs).141 As such, they face certain disclosure 

requirements under U.S. securities laws. These “big 

three” oil companies are much more concerned about 

reputational risk than most other Chinese firms, and 

this positively influences their behavior in Africa. 
75

The global energy market is also highly competitive, and China’s three oil giants must compete with 

Western majors from a position of relative technological weakness. While China’s companies are developing oil fields in Africa, for now they are not nearly as 

technically proficient as Western firms, especially in 

offshore exploration and production. For these reasons, Chinese oil companies have tended to be followers in Africa, not leaders. Angola is a case in point. For 

all of the media attention to the way China was able 

to win certain oil blocks and production “off-take” 

agreements in Angola, Chinese firms had interests in 

a mere 12 oil blocks—all only as non-operators. U.S. 

firms, by contrast, acted as operators of 11 oil blocks 

in Angola, and were also present as non-operators for 

five other oil blocks.142

Moreover, China’s controversial use of nonmarket 

tools such as infrastructure-for-oil deals in Angola 

may be less unreasonable—and less repeatable in the 

future—than meets the eye. In Angola, China’s EXIM 

Bank pledged massive, oil-backed financing of some 

$14.5 billion for Luanda’s ambitious post-war reconstruction program, including over 100 projects in the 

areas of energy, water, health, education, telecommunications, fisheries, and public works. One Chinese 

academic asserted that Chinese government financing 

of infrastructure in Angola was not linked to deals by 

Chinese NOCs to win shares in oil blocks, but rather 

a means for Beijing to secure its loans to the government of Angola.143 This explanation is at least partially 

correct. “Oil-for-infrastructure” is arguably merely a 

creative form of project finance that, for Beijing, also 

has the dual benefit of securing oil supplies. Moreover, this model may not be used again, at least within Angola. Some Angolans have complained that the 
76

infrastructure-for-oil deals with China have shackled 

their oil revenues to that of repaying Chinese loans.144

Angola is also moving beyond the post-reconstruction 

phase of its history. Consistent with this, the Angolan 

government has looked to limit its exposure to further 

oil-backed loans with the Chinese, and the Chinese 

have not been particularly successful in Luanda in 

bidding for new oil blocks. 

Another often raised concern is that China (and 

to a lesser extent, India) is somehow trying to negotiate long-term supply contracts in Africa to ensure 

that it can import oil and gas in the event of a crisis 

or supply disruption. In the case of oil, this concern 

is overblown; in the case of natural gas, it is outright 

misplaced. Other than the special case of post-conflict 

Angola, China has not cornered a significant amount 

of African oil at this time through other production 

off-take agreements, and is unlikely to emphasize 

this strategy in future deals on the continent.145 Yes, 

there will be further infrastructure deals by China in 

the future, as there have been in the last 2 years in 

emerging oil and gas producers in Ghana and Tanzania, but these latest deals have not included oil offtake agreements. At the end of the day, much of the oil 

extracted by Chinese companies in Africa is not even 

exported back to China, but instead sold on the world 

market. Far from “cornering the market,” Chinese 

energy companies (and those from other emerging 

countries) will continue to use benign farm-ins to existing energy projects led by Western majors and independents as their primary market-entry strategy. As 

working partners in these deals, they will continue to 

be in “learning mode,” familiarizing themselves with 

the technology needed offshore for deepwater drilling 

and platform maintenance and skills needed onshore 
77

for regulatory compliance with African host governments. Over time, Chinese firms will increasingly act 

as lead operators in future deals, but still will not act 

to corner Africa’s oil or gas markets. 

Moreover, concerns about Chinese long-term supply contracts for natural gas are outright misplaced. 

In the case of natural gas, any long-term contracts 

supply contracts—assuming that they are armslength, market-drive transactions not influenced by 

corruption—should be welcomed, not rejected, by African nations. Why? Any NOC and/or international 

consortia needs long-term purchase deals to reduce 

project risk and secure financing because major gas 

projects require huge capital investments in offshore 

and onshore infrastructure investments running into 

the tens of billions of dollars. This is precisely why, in 

March 2013, Italy’s ENI farmed in China’s CNPC into 

its Area 4 natural gas project in Mozambique, and why 

the U.S. firm Anadarko had earlier farmed in Japanese 

trading company Mitsui: to sew up long-term Asian 

customers and supply contracts that will make their 

projects feasible. 

Does Africa Benefit from Chinese 

Energy Investment? 

Again, from the African perspective, increased 

Chinese participation in Africa’s energy sector should 

be seen as a big positive—if on fair, market-based 

terms. Chinese (and other Asian) players have bid up 

prices for acreage, brought new risk capital, invested 

in energy-related infrastructure, and found Chinese 

(and other Asian) customers for their oil and gas. It 

is good news from Africa’s point of view that some 

Western oil industry participants have occasionally 
78

complained about China overbidding for acreage on 

the continent. Some Western observers have criticized 

these acquisitions of exploration blocks, asserting that 

some of them are economically unattractive or even 

technically unviable to develop.146 A more logical explanation for investment by China’s NOCs in Africa 

is not overbidding, however, but rather that they are 

behaving as rational economic actors. What may seem 

like marginal exploration blocks or existing production fields to a Western major with sophisticated risk 

models, precisely calculated “costs of capital,” and 

disciplined capital budgeting processes may seem 

quite profitable to China NOCs, which enjoy lower 

personnel costs, lower cost of capital due to lending from state-owned banks, and thus lower “hurdle 

rates” for expected profitable projects. 

The West, moreover, should also not be alarmed 

when Western oil firms sell their assets in Africa to 

Chinese (or other Asian) energy companies. Western firms, armed with the latest industry technology, 

are able to redeploy their capital on a global basis to 

exploit higher returns. At present, their most promising investments are as developers and operators of 

ultra-deepwater tracts in places like Angola and Ghana. This option is not currently available to Chinese 

NOCs, who still do not have the technical capacity to 

develop and operate ultra-deepwater offshore blocks, 

where much of the new oil and gas in Africa lies. Consequently, for now, Chinese NOCs have contented 

themselves to farming-in as non-operators in deepwater blocks and to bidding on onshore and shallower 

offshore blocks as operators. For example, in November 2011, China’s Sinopec bought an 80 percent stake 

in Shell Oil’s Cameroon subsidiary, with the 20 percent remainder owned by NOC SNH. This gave China 
79

stakes in 12 offshore blocks in Cameroon. For its part, 

Shell will redeploy the capital from this sale within 

its global business to locations with a higher expected 

rate of return or return the capital to its shareholders. 

China and Rest of Asia: Biggest Winners from 

African Energy Expansion.

Aside from the microeconomic issue of the degree 

of involvement of Chinese NOCs in Africa’s oil and 

gas sectors is the broader macroeconomic issue of how 

important Africa has been as the source continent for 

China’s imported oil and gas. As noted previously, Africa was the source of 33 percent of China’s oil imports 

in 2010, and this figure is likely to rise in the future. 

Even with the growth of its domestic natural gas production from shale and other nonconventional sources, China will still require over 130 bcm of natural gas 

imports by 2030. This is because while China’s shale 

gas growth will accelerate after 2020, China’s gas demand will increase from just over 150 bcm at present to 

more than 600 bcm in 2030. While much of China’s imported natural gas may come from Russia, Turkmenistan,147 Australia, and even North America, Chinese 

buyers will also seek diversified sources of natural gas 

from Africa, including from Gulf of Guinea countries 

such as Angola and Nigeria on the Atlantic side of the 

continent. 

This monograph asserts that there has been a 

loose, inverse correlation between Africa’s declining 

importance for U.S. energy security and its increasing importance for China. China and the rest of Asia 

have benefited indirectly but significantly from the 

increased supplies of shale oil and gas in the United 

States in the form of lower global prices, and will ben-
80

efit directly the most from increased oil and gas supplies from Africa in the coming years. The changing 

energy security picture in North America has meant 

that new LNG projects originally targeting the U.S. 

market, such as that of Chevron in Angola, will be 

looking for Asian customers, including in China. IOC 

consortia leading natural gas projects in Mozambique 

and Tanzania have already started to accept Chinese 

and other Asian equity investment and are trying to 

lock in Chinese and other Asian customers. CNPC’s 

$4.21 billion farm-in of 20 percent of ENI of Italy’s offshore Mozambique Area 4 gas fields was the first such 

deal for China. Others will follow in the future. 

One could argue that Japan will be the biggest 

beneficiary in Asia of these trends, because while its 

economy is only slightly smaller than that of China, 

its dependence on oil and gas imports is far higher. 

The author believes, however, that China will benefit 

even more over time than Japan from African energy 

because China’s economy will likely continue to grow 

much faster than that of Japan and, as noted previously, China’s dependence on energy imports will 

continue to increase both in absolute terms and relative to domestic supplies. Also, from a strategic point 

of view, the energy security of China’s superpower 

rival in the 21st century, the United States, has increased dramatically because of the shale oil and gas 

boom, and will move toward relative energy independence as North American supplies increase. When 

both China and the United States were big energy 

importers, they both felt vulnerable. In a few years, 

however, when the United States is more energy secure, China’s own energy insecurity will be felt even 

more acutely by Beijing because its perceived main 

rival is more secure. This is particularly so because 
81

the PRC has an autocratic government that is proud 

of its country’s development, but also highly insecure 

and distrustful of the United States.148 In this context, 

Africa will be not only a source of natural resources 

for China, but also an increasingly important source 

of strategic resources—oil and gas.

VII. AFRICAN ENERGY AND CHINA’S 

EMERGING TWO-OCEAN MILITARY 

STRATEGY 

One academic team discussing African energy has 

asserted:

In the strategic policy communities of both the United 

States and China, there has been a knee-jerk blurring 

between competition in commerce between U.S. and 

Chinese energy firms and the potential for strategic 

competition by one country to deny resources to the 

other.149 (emphasis added) 

Up to here, much of the author’s research in this 

monograph has been presented largely in terms of 

the competition and cooperation between IOCs and 

NOCs—i.e., private and state-owned companies—

from the United States, China, and other nations for 

exploration and production assets and licenses on the 

African continent. The strategic, country-level effort 

by China to secure its energy imports from Africa (and 

the Middle East) will now be examined. 

An October 2012 Chatham House study referred to 

the oil trade with “Middle East exporters,” but more 

accurately should have substituted this language with 

“African and Middle East exporters”: 
82

The axis of the oil market is shifting from the trade 

between the Middle East exporters and U.S. and European importers to one that links Asian developing 

markets to the Middle East, which no longer has sufficient oil to support these markets’ growing needs. 

With this shift, the study then posed the questions: 

Who will carry responsibility for the physical security 

of Middle East oil export now that these mostly go to 

Asian markets rather than the US or Europe?150

The short answer is, in the short- and mediumterm, the U.S. Navy will continue to protect the global 

commons around the Middle East (and Africa) for the 

benefit of the United States, its allies, and other nonally countries that “free ride” on the security, such 

as China. However, that academic team also wrote 

that while:

At present . . . China has to depend on the United 

States and its allies to guarantee security of the main 

international shipping lanes and major ‘choke points’ 

from the Middle East through which so much of its 

imported oil comes. . . . Beijing is attempting to reduce 

this dependence on United States military power by 

increasing access to oil and gas imports from other regions, developing alternative routes and increasing its 

naval capacity.151

Alternative land routes that China is developing 

to import African and Middle East oil and gas have 

been collectively dubbed the “New Silk Road.” This 

refers to China’s efforts to help construct a modern 

grid of overland pipelines, roads, and railways from 

China to Central Asia and the Middle East so that a 

portion of its energy supplies can circumvent naval 
83

chokepoints and potential blockades or embargoes.152

Other maritime-and-land routes contemplated or under construction include an oil pipeline from Gwadar, 

Pakistan, to Xinjiang in western China (not likely due 

to political instability),153 an oil pipeline from the Bay 

of Bengal in Burma to China’s Yunnan Province (gas 

pipeline opened May 2013, an oil pipeline opening in 

2014, road/rail links opening later),154 and a $20 billion or more canal or land bridge across the Isthmus of 

Kra in Thailand (feasible, but still in conceptual stage). 

Over the longer term, a rising, wealthy, nationalistic and assertive China will also seek to increase its 

naval capabilities to secure its ever increasing energy 

imports from Africa and the Middle East and keep the 

Chinese Communist Party in power. Beijing’s April 

2013 Defense White Paper was quite clear on the linkage between its navy and energy security: “It is an 

essential national development strategy to . . . build 

China into a maritime power . . . Security issues are increasingly prominent, involving overseas energy and 

resources . . .”155

China has already been modernizing its navy and 

shifting its strategy from a “coastal defense” to a “far 

seas defense.”156 Military strategists have noted that 

China has developed a “two island chain” military 

doctrine in East Asia focused on its claims on Taiwan 

and the South China Sea. (See Map 1.) An ongoing 

evolution in this doctrine emphasizes not only the 

two island chains in the Pacific, but a “two oceans”

strategy that includes the Indian Ocean.157 The rising 

importance of the Indian Ocean in China’s views of 

its national security derives from Beijing’s increasing 

concern about: 1) transportation chokepoints for energy and other trade in the Straits of Hormuz, Mandeb, and Malacca; and, 2) the rise of India, with which 
84

it has had repeated border clashes. The “Malacca 

Dilemma”158 refers to the fact that roughly 80-85 percent of China’s oil imports traverse this key strait.159

In its worst-case-scenario, Beijing is concerned about 

the risk of a U.S. naval blockade of China’s energy 

imports should hostilities break out over Taiwan (or, 

even less likely, over the Senkaku/Diaoyutai Islands 

with Japan).160 Furthermore, Washington’s increasing 

energy security will make Beijing’s own increasing energy insecurity be felt even more acutely, pushing the 

People’s Liberation Army (PLA) to accelerate adoption of a “two ocean” military strategy that includes 

an enduring presence in the Indian Ocean as well as 

the Pacific. 

Source: T. X. Hammes, Offshore Control: A Proposed Strategy for an 

Unlikely Conflict, Institute for National Strategic Studies (INSS) 

Strategic Forum, Washington, DC, June 2012, p. 2.

Map 1. Two Island Chains in Military Doctrine

of Peoples Republic of China.
85

What form will this “enduring presence” take? It 

is already clear that China is interested in building a 

regional support network of refueling and resupply 

ports in the Indian Ocean, sometimes referred to as a 

“string-of-pearls” strategy. This includes South Asian

ports in littoral countries such as Pakistan (where 

Beijing has aided in constructing major port improvements at Gwadar), Sri Lanka (at Hambantota), Bangladesh (at Chittagong), and Burma, but also African

ports, such as the Red Sea’s Port Sudan in Sudan, Djibouti, at the Strait of Mandeb,161 and the Seychelles, 

with which Beijing engaged in talks in December 2011 

to establish a resupply facility, ostensibly to fight piracy.162 There is also debate within China about whether 

to establish military bases overseas with infrastructure in the Indian Ocean and permanently stationed 

personnel. While some argue that China is unlikely to 

seek to establish a regional base network in the Indian 

Ocean, given the PRC’s self-imposed policy against 

the “imperialist” basing of military forces in foreign 

countries, others (including the author) assert that 

this appears inevitable given China’s energy needs. In 

support of the latter viewpoint, one academic recently 

argued that: 

While the Chinese government continues to proclaim 

its opposition to foreign bases, its practical actions and 

the words of its longest serving commander and the 

father of the modern [Chinese Navy] indicate otherwise.163

The author’s own view is that China’s recent participation in anti-piracy operations in Horn of Africa, 

in due time, will be recognized as a historical stepping 

stone toward a more active, permanent Chinese naval presence in the Indian Ocean. (See Map 2.) This 
86

presence may eventually include a naval base in close 

ally (and India arch-rival) Pakistan, but would mainly 

be comprised of a network of loose resupply arrangements in the Indian Ocean (including the Red Sea and 

Gulf of Aden) under the cover of supplying partner 

nations with either overall bilateral development assistance and/or more explicitly defense cooperation. 

In the future, these cooperative arrangements could 

be concluded with Sudan, Eritrea, Djibouti, the Seychelles, and Tanzania, for example. A January 2013 article in a Chinese state-run newspaper advised against 

building U.S.-style military bases, but advocated the 

establishment of a number of so-called “Overseas 

Strategic Support Bases.” According to an Englishlanguage translation, the article indicated that:

In the future, the Chinese Navy will establish its first 

batch of support bases in [the] Indian Ocean. . . . These 

bases can be divided into three levels: First ship fuel 

and material supply bases in peacetime such as the 

Port of Djibouti, Aden port of Yemen, and Salalah 

Port of Oman . . . the second is relatively fixed supply 

bases for warship berthing, fixed-wing reconnaissance 

aircraft, and the naval staff ashore rest, such as the 

ports of [the] Seychelles. China can build those bases 

by sign[ing] a short-term or medium-term agreement 

with [the] Seychelles; the third [are] fully-functional 

center[s] for replenishment, rest, and large warship 

weapons maintenance such as in Pakistan under medium- and long-term agreements.164
87

Source: www.geographicguide.com.

Map 2. The Indian Ocean, Including Strait 

of Malacca.

Whatever form it takes, over the long term, Beijing 

seems destined to develop a more muscular security 

cooperation policy vis-à-vis the Indian Ocean to ensure the security of its energy imports from the Middle East, East Africa, and the Gulf of Guinea in West 

Africa. While likely not welcomed by Washington or 

New Delhi, such a naval presence would not necessarily be inimical to U.S. or Indian interests, and could 
88

actually contribute to the protection of the global commons. This would particularly be the case if, some 

would say optimistically, China’s peaceful rise really 

does lead it to be more of a responsible stakeholder 

in global prosperity. Some academics also argue that 

China, the United States, and India should work together in a “strategic triangle” to “preclude rivalry 

and promote collaboration in the Indian Ocean”165 or 

seek “a peaceful transition from American unipolarity 

at sea . . . and towards an American-Indian-Chinese 

condominium of sorts.”166

ENDNOTES

1. “World Energy Outlook 2012,” International Energy Agency (IEA), November 2012, p. 135.

2. There tends to be two types of projections of future oil and 

gas production and reserves: conservative and speculative. On 

the one hand are the mainstream projections made by major institutions such as the IEA in Paris, France; OPEC in Vienna, Austria; 

the EIA and USGS in Washington, DC, as well as annual global 

estimates made by IOCs such as the U.S. firm ExxonMobil and the 

UK’s BP. For sure, these estimates of future production and reserves are based on sophisticated and rigorous analysis, but they 

also tend to be conservative. On the other hand, there is a band 

of small, international exploration companies now hyperactive in 

Africa, mostly from Australia, Canada, the UK, and the United 

States. These small companies—the African analogues to the Texas wildcatters—are hungry for new discoveries and desperate for 

the huge amounts of capital needed for aeromagnetic, 2D, and 

3D surveys, and for exploration, appraisal, and production wells. 

With these firms, there is a tendency to describe licenses or blocks 

as “highly prospective” and use “independent,” third-party subject matter experts to corroborate these companies’ optimistic 

projections. This monograph includes both these conservative 

and speculative projections.

3. “Continent,” available from en.wikipedia.org/wiki/Continent.
89

4. “Geography of Africa,” available from en.wikipedia.org/wiki/

Geography_of_Africa.

5. The seven island nations in Africa are Cape Verde, Sao 

Tome and Principe, Equatorial Guinea (which also has a mainland enclave), Madagascar, the Comoros, the Seychelles, and 

Mauritius.

6. Chakib Khelil, “A Framework for Investment in Africa’s 

Energy Infrastructure,” Oxford Energy Forum, Oxford, UK, November 2012, pp. 8-9.

7. “Is East Africa the Next Frontier for Oil?” Time, March 10, 

2010.

8. Alex Vines, “Opportunities and Challenges in Africa’s 

Changing Energy Landscape,” Oxford Energy Forum, Oxford, 

UK, November 2012, p. 10.

9. Khelil, “A Framework for Investment in Africa’s Energy 

Infrastructure,” pp. 8-9.

10. “Africa Oil and Gas: A Continent on the Move,” Ernst & 

Young, 2011, EYG no. DW0100, No. 1107-1271904, p. 3, available 

from www.ey.com/GL/en/Industries/Oil---Gas/Africa-oil-and-gas--acontinent-on-the-move---Regional-prospects-and-opportunities-in-theoil-and-gas-sector; and Paul Collier, “The Plundered Planet: Why 

We Must—and How We Can—Manage Nature For Global Prosperity,” New York: Oxford U.P., 2010.

11. See also Duncan Clarke, “Crude Continent,” London, UK: 

Profile Books, 2008, for an interesting review of the history and 

politics of oil in Africa. 

12. “Energy and Security in Africa: Meeting the Challenge in 

Petroleum Producing States,” Abuja, Nigeria: Africa Center for 

Strategic Studies, March 6-11, 2005, p. 10.

13. “Campos Basin,” available from en.wikipedia.org/wiki/Campos_Basin.
90

14. “Lithosphere,” available from en.wikipedia.org/wiki/

Lithosphere.

15. Available from en.wikipedia.org/wiki/Rift.

16. Available from en.wikipedia.org/wiki/Graben.

17. “Pre-Salt Layer,” available from en.wikipedia.org/wiki/Presalt_layer.

18. “West Africa,” available from www.cobaltintl.com/assets/

westafrica.

19. Jacques Deverchere, “The North African Margin (Western 

Mediterranean Sea): Structure, Evolution, and Active Deformation,” ESC 2010, September 6-10, 2010, p. 14.

20. J. D. Fairhead, “The West and Central African Rift Systems: Foreward,” Tectonophysics, Vol. 213, 1992, pp. 139-140.

21. Kristjan Saemundsson, “The East African Rift System—

An Overview,” Short Course III, UNU-GTP, Lake Naivasha, Kenya, October 24-November 17, 2008.

22. Not discussed in this report are the French overseas department of Reunion, an island east of Madagascar; Mayotte, a 

French collectivity north of the Madagascar Channel; and the 

French islands of Iles Glorieuses, Brassas de india, which are also 

part of the Southern and Antarctic Lands and, like Juan de Nova, 

also found in the Madagascar Channel. See Map 2, available from 

commons.wikimedia.org/wiki/File:France_doutre-mer_2007_fr.png, for 

more details.

23. James D. Fairhead, “The Mesozoic West and Central African Rift System: Qualitative Evaluation,” Search and Discovery, 

Article #30077, 2009.

24. “World Energy Outlook 2012,” p. 117.

25. Ibid.
91

26. Brian Swint, “Chariot Oil & Gas Plans More Namibia 

Wells After Two Dry Holes,” New York: Bloomberg, September 

21, 2012.

27. “Africa Oil and Gas,” p. 5.

28. “Country Analysis Briefs—Equatorial Guinea,” Washington, DC: U.S. Energy Information Administration, February 28, 

2012.

29. “Gabon—Country Analysis Brief,” Washington, DC: U.S. 

Energy Information Administration, January 17, 2012.

30. Ibid.

31. “Regions Petroliferes en Afrique” (“Petroleum Regions in 

Africa”), available from fr.wikipedia.org.

32. “Cameroon,” available from bowleven.com/Cam-Gab.

33. “Cameroon—Expanding into Cameroon,” available from 

www.madisonpetro.com.

34. “Africa Oil and Gas,” p. 5.

35. “Benin: des gisements de petrole ont ete decouverts au 

large des cotes du Benin” (“Benin : Oil Deposits Discovered Along 

Coast of Benin”).

36. See africanpetroleum.com.au/our-projects/sierra-leone.

37. U.S. Geological Survey Minerals Yearbook—2011, Advance 

Release, Washington, DC: U.S. Geological Survey, p. 35.5; Oil 

Exploration in Sierra Leone in 2011 . . . Maybe a New Frontier,” 

June 14, 2011.

38. “Hyperdynamics Announces Updated Prospective 

Oil Resources Evaluation,” February 14, 2013, available from 

investors.hyperdynamics.com; and “Tullow Agrees to Farm-in 

Guinea Concession,” November 20, 2012.
92

39. David Brown, The Challenge of Drug Trafficking to Democratic Governance and Human Security in West Africa, Carlisle, PA: 

Strategic Studies Institute, U.S. Army War College, May 2013.

40. Available from www.far.com.au/irm/content/senegal.

41. Available from www.mbendi.com/indy/oilg/af/gm/p0005.

42. “Overview—Mauritania,” available from www.

chariotoilandgas.com/operations/mauritania.

43. “Historique de l’Exploitation” (“History of Exploration”), 

Morocco: Office National des Hydrocarbures et des Mines.

44. The Sahrawi Arab Democratic Republic (SADR) is a partially recognized state that claims sovereignty over the entire territory of Western Sahara, a former Spanish colony. SADR was 

proclaimed by the Polisario Front in 1976. The SADR government 

controls about 20-25 percent of the territory it claims, while Morocco controls the rest of the disputed territory. States that recognize the SADR’s claims to sovereignty are mostly in Africa, 

though some non-African states do recognize it. It is currently not 

recognized by the United Nations (UN) as being a sovereign state. 

This information is available from https://en.wikipedia.org/wiki/

Sahrawi_Arab_Democratic_Republic.

45. “Oyster Oil Secures Djibouti Acreage,” Petroleum Africa, 

September 20, 2011.

46. Angelia Sanders et al., “Emerging Energy Resources in 

East Africa,” Norfolk, VA: Civil-Military Fusion Center Mediterranean Basis Team, September 2012, p. 3.

47. “Country Profile: Kenya,” Toronto, Canada: Cormark Securities, February 3, 2011, p. 15.

48. “Kenya to Gazette up to 9 New Oil and Gas Exploration 

Blocks,” Reuters, February 12, 2013.

49. “Kenya,” available from www.apachecorp.com/Operations/

Kenya.
93

50. “Ophir Energy Reveals Jodari Field Discoveries,” December 14, 2012; see www.bg-group.com/Ourbusiness/WhereWeOperate/

Pages/Tanzania; “Papa-1—Play Opening First Cretaceous Gas Discovery Outboard of the Rufiji Delta, Block 3, Tanzania,” Ophir 

Energy PLC press release, August 2, 2012.

51. “Mozambique: Oil & Gas Exploration in 2011-2012,” available from mergersandacquisitionreviewcom.blogspot.com/2011/07

/mozambique-oil-gas-exploration-in-2011.html.

52. “Mozambique,” available from anadarko.com.

53. “Oil, Gas and Security in Mozambique,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-Mozambique.

54. “Mozambique Fact Sheet 2013,” The Woodlands, TX: 

Anadarko Petroleum, 2013.

55. Debbie Stevenson, “Investors Make a Move on Madagascar’s Oil Reserves,” November 20, 2012.

56. “Madagascar,” available from www.nikoresources.com/

operations/madagascar.

57. “Oil, Gas and Security in Madagascar,” available from 

www.thinkafricasecurityafrica.org.

58. “Offshore Seychelles a ‘Flagship Project’,” available from 

www.whlenergy.com.au/irm/showStatic Category.

59. “Mauritius: ONGC Considering Oil and Gas Exploration 

Rights,” July 8, 2007, available from energy-pedia general news.

60. “Africa Country Profiles,” available from www.mebendi.

com/indy/oilg/af/p0005.htm.

61. EIA Short-Term Energy Outlook (STEO), as provided to 

author by USAFRICOM source on April 26, 2013.

62. Ivan Sandrea, “The Building Blocks of Africa’s New O&G 

Industry,” Oxford Energy Forum, Oxford, UK, November 2012, 

p. 3.
94

63. Ibid.

64. Rolake Akinkugbe, “Sub-Saharan Oil and Gas 2012: A 

Business Africa Guide,” Lomé, Togo: Ecobank Capital, February 

2, 2012.

65. Stanley Reed, “Finding Success on the Oil Frontier,” The 

New York Times, July 3, 2012.

66. “Nigeria’s Slack and the Rise of the Rest,” Africa Oil & Gas 

Report, May 2012, pp. 4, 12.

67. Sandrea, “The Building Blocks of Africa’s New O&G Industry,” p. 3.

68. David L. Goldwyn, “Pursuing U.S. Energy Security Interests in Africa,” prepublication draft, January 2009, p. 1.

69. Available from en.wikipedia.org/wiki/Movement_for_the_

Emancipation_of_the_Niger_Delta.

70. “Energy and Security in Africa: Meeting the Challenge in 

Petroleum Producing States,” pp. 11, 16.

71. Despite periodic surges in resource nationalism in several 

African countries, Africa is a uniquely open market for foreign investment, particularly compared with Russia and Latin America, 

and has well over 50 percent of energy production coming from 

IOCs. See Goldwyn, “Pursuing U.S. Energy Security Interests in 

Africa,” p. 7.

72. Bas Percival et al., “Gambling in Sub-Saharan Africa—Energy Security through the Prism of Sino-African Relations,” The 

Hague, The Netherlands: Netherlands Institute of International 

Relations, July 2009, p. v.

73. “High Prices Fuel Exploration Frenzy,” New African, April 

17, 2012.
95

74. Daniel Fikreyesus, “Oil and U.S. Foreign Policy Toward 

Africa,” Ph.D. dissertation, Georgia State University, May 5, 2012, 

p. 9.

75. “Energy and Security in Africa: Meeting the Challenge in 

Petroleum Producing States,” p. 24.

76. Of course, overall U.S. oil imports are declining but still 

important. As such, Africa remains important in diversifying U.S. 

energy import. See Fikreyesus, p. 1.

77. Calculations based on Table A21, “Annual Energy Outlook 2013,” Washington, DC: U.S. EIA, p. 160, released May 2, 

2013.

78. Monica Enfield, “Africa’s Risk Outlook,” Oxford Energy 

Forum, Oxford, UK, November 2012, p. 4.

79. World Energy Outlook 2012, Paris: International Energy 

Agency (IEA), 2012, p. 2.

80. Ibid., p. 2.

81. Carolyn Pumphrey, ed., The Energy and Security Nexus: A 

Strategic Dilemma, Carlilsle, PA: Strategic Studies Institute, U.S. 

Army War College, November 2012, pp. 30, 32.

82. “Wood Mackenzie at Gastech 2012: Signposts Suggest a 

More Interconnected Global Gas Market in the Future,” London, 

UK: Wood Mackenzie Media Centre, October 9, 2012.

83. Please note that, although Africa’s natural gas production 

actually fell in 2011 compared to 2010 (to 203 bcm from 209 bcm), 

this was due primarily to supply disruptions in Libya due to the 

civil war in that country. With Libya excluded, natural gas production for the rest of the continent continued to increase. See also 

“Natural Gas in Africa—The Frontiers of the Golden Age,” Ernst 

& Young, 2012, p. 6.

84. World Energy Outlook 2012, IEA, p. 139.

85. “Natural Gas in Africa—The Frontiers of the Golden Age,” 

Ernst & Young, 2012, p. 6.
96

86. Elias Pungong, “Africa’s Gas (R)evolution,” Oxford Energy Forum, Oxford, UK, November 2012, p. 7.

87. “Natural Gas in Africa—The Frontiers of the Golden Age,” 

Ernst & Young, 2012, p. 3.

88. Available from www.ey.com/GL/en/Newsroom/News-releases/News_Growing-role-for-Africa-in-the-Golden-Age-of-Gas.

89. World Energy Outlook 2012, IEA, p. 134.

90. Guy Chazan, “East Africa: Embarrassment of Riches’ 

Hard to Exploit,” The Financial Times, October 8, 2012.

91. “Oil and Gas: East Africa’s Race to Get Ready,” The Africa 

Report, October 1, 2012.

92. “East Africa Seen As New Frontier for Gas: Report,” AFP, 

October 30, 2012.

93. “East Africa Faces Technical and Commercial Challenges 

to Bring Its 100 tcf of Discovered Gas to Market,” www.woodmacresearch.com, August 22, 2012.

94. Available from www.lngworldnews.com/wood-mackenzie100-tcf-of-gas-found-in-mozambique-and-tanzania-to-date/.

95. Angelia Sanders et al., “Emerging Energy Resources in 

East Africa,” London, UK: Civil-Military Fusion Centre Mediterranean Basis Team, September 2012.

96. “Natural Gas in Africa—The Frontiers of the Golden Age,” 

Ernst & Young, 2012, p. 3.

97. Pungong, p. 7.

98. “Natural Gas in Africa—The Frontiers of the Golden Age,” 

Ernst & Young, 2012, p. 4.

99. Akinkugbe.
97

100. “African Oil: A Priority for U.S. National Security and 

African Development,” undated, p. 6, available from www.iasps.

org/strategic/africawhitepaper.pdf.

101. Another factor explaining the decline in U.S. oil imports 

from Africa is that two refineries on the U.S. east coast were idled 

in 2012, per EIA Short-Term Energy Outlook (STEO), as provided 

by USAFRICOM source on April 25, 2013.

102. Brad Plumer, “Where the U.S. Imports Its Oil From, in 

One Map,” The Washington Post, January 19, 2013.

103. Joe Brock, “Analysis: Nigeria Losing Ground in Changing Oil World,” www.Reuters.com, February 25, 2013.

104. “Nigeria,” Country Background Note, U.S. Energy Information Administration, October 16, 2012.

105. See also www.eia.gov/pressroom/releases/press374.cfm for 

this analysis.

106. “Within the Next Decade U.S. Foreign Oil Imports Are 

Forecasted to Fall More Than 50%,” December 6, 2012, available 

from www.stockhouse.com.

107. By 2035, imports into the United States are expected to 

be only 3.4 million bpd, and North America as a whole (including 

Canada and Mexico) may become a net exporting region. ExxonMobil predicts that energy use in OECD countries will remain 

essentially flat until 2040, while non-OECD energy demand will 

grow by close to 60 percent, making overall global energy demand about 30 percent higher in 2040 compared to 2010.

108. EU member-states purchase three-fifths of Algeria’s LNG 

exports, while almost all of Libya’s gas production is exported to 

Europe via the Greenstream pipeline under the Mediterranean to 

Italy. See Lord Aikins Aduei, “Global Energy Security and Africa’s Rising Strategic Importance,” January 6, 2012, available from 

www.modernghana.com; and the country profile on Libya. 

109. “Africa Oil and Gas,” p. 3.
98

110. Goldwyn, “Pursuing U.S. Energy Security Interests in 

Africa,” p. 7.

111. Akinkugbe.

112. See also John P. Banks, “Key Sub-Saharan Energy Trends 

and their Importance for the U.S.,” Brookings Africa Growth Initiative, March 13, pp. 8-13, for more analysis of the broader issue 

of the importance of energy for development. The author argues 

that “Failure [in Africa] to expand energy access, reduce energy 

imports, diversify energy sources and manage new-found oil and 

gas wealth for the benefit of society, especially the poor, directly 

impacts U.S. interests.” The author lists these U.S. interests as humanitarian, national security, and economic. 

113. David E. Brown, Hidden Dragon, Crouching Lion: How China’s Advance in Africa is Underestimated and Africa’s Potential Underappreciated, Carlisle, PA: Strategic Studies Institute, U.S. Army 

War College, September 2012, p. 29.

114. Monica Enfield, “Africa’s Risk Outlook,” Oxford Energy 

Forum, Oxford, UK, November 2012, p. 4.

115. Between 1994 and 1998, the Chinese government reorganized most state-owned oil and gas assets into two vertically 

integrated firms: CNPC and Sinopec. These two conglomerates 

operate a range of local subsidiaries and together dominate China’s upstream and downstream oil markets. One additional stateowned oil firm that emerged over the last several years was the 

CNOOC, which is responsible for offshore oil exploration and 

production. See “China—Background,” Country Analysis, Washington, DC: U.S. Energy Information Agency, September 4, 2012.

116. Ibid.

117. Javier Blas, “China Becomes World’s Top Oil Importer,” 

The Financial Times, March 4, 2013.

118. Shelly Zhao, “The Geopolitics of China-Africa Oil,” China Briefing, April 13, 2011.
99

119. Coming in second to fourth in China’s national interests 

in Africa are: China’s commercial interests in promoting trade 

and investment on the continent, securing political support from 

African nations in the UN, and winning diplomatic recognition at 

the expense of Taiwan (the “One China Policy”). 

120. China’s shale deposits are spread across four regions, 

including Sichuan and Shaanxi Provinces. Its shale deposits are 

more geologically complex than in the United States and found at 

depths of 3,000-5,000 meters compared with less than 3,000 meters for U.S. shale deposits. China’s National Energy Administration forecasts shale gas output by 2020 of 60-100 bcm. See “Focus: 

Unconventional Oil & Gas—Europe, Africa, Asia Governments 

Assess Shale Development Policies,” Oil & Gas Journal, available 

from www.ogj.com/articles/print/vol-110/issue-07.

121. Zhao.

122. “Sino-Africa Trade and Financial Cooperation: History 

and Trends,” Bank of China, May 2011.

123. Zhao.

124. The financial, economic, and developmental aspects of 

China’s oil-for-infrastructure deal were its primary attractions. 

Political considerations may also have been deciding factors, 

however. The Angolan government was able to rebuff demands 

from the International Monetary Fund for structural adjustments 

in 2004 because it secured this $14.5 billion loan from China. Old 

fashioned third-world and socialist solidarity between China and 

Angola’s ruling party, the nominally Marxist Peoples Movement 

for the Liberation of Angola (MPLA), may have also been a factor 

in winning internal approval within the Chinese government and 

the acceptance of the Chinese by Luanda. 

125. CNCP’s acquired license includes a 100 percent share in 

Block Bilma and an 80 percent share in Block Tenere. The holder 

of the remaining 20 percent share was Canada’s TG World.

126. Sanusha Naidu, “Africa Becoming Low Cost Manufacturing Hub for Chinese Investments,” Pambazuka News, May 27, 

2010. 
100

127. Sudan and South Sudan also became a major diplomatic 

challenge for China. Most notably, a dispute between Sudan and 

South Sudan over oil export transport fees broke out, leading to 

a shutoff in oil exports in November 2011. Reflecting the importance of Sudan and South Sudan for Chinese energy imports, Beijing dispatched its special envoy for African Affairs to Khartoum 

and Juba in December 2011 to propose a solution to the dispute, 

dispatched a new envoy in early May 2012 in a renewed diplomatic effort, and joined other UN Security Council members that 

same month in unanimously supporting Resolution 2046, which 

called on Sudan and South Sudan to halt cross-border attacks and 

return to negotiations. (The Presidents of South Sudan and Sudan agreed in April 2013 to resume oil exports via the existing 

pipeline.) See “Sudan, South Sudan to Open Border, Resume Oil 

Exports,” Associated Press, April 12, 2013. 

128. As quoted in Christopher Alesi and Stephanie Hanson, 

“Expanding China-Africa Oil Ties,” New York: Council on Foreign Relations, February 8, 2012.

129. “Xi Jinping Wraps Up Africa Trip in Congo,” BBC News, 

March 29, 2013.

130. Chad, an inland nation where the investment risk-return 

facing Chinese NOCs in the early-2000s probably looked poor, 

may have been a case where the politics of winning diplomatic 

recognition from N’djamena (and pushing out Taiwan’s NOC) 

may have induced Beijing to instruct its NOCs to make primarily 

policy-driven investments in Chad’s prospective oil fields and in 

new pipelines and refinery capacity. 

131. Another key point is that it is important to separate a 

discussion of China’s NOCs in Africa from a discussion of China’s 

government/Communist Party foreign policy on the continent. 

Of course, there is a close relationship between the NOCs and the 

Chinese state/party. This relationship is not only a formal ownership relationship under which the Chinese government, through 

its State-Owned Asset Supervision and Administration Commission, owns shares of the NOCs, which are hybrid organizations 

that are both state owned and partially owned by private Chinese and international stock investors. The key executives of the 
101

“big three” Chinese oil companies are also all senior members of 

the Communist Party, and there is considerable rotation between 

the companies and the commissions and ministries that oversee 

them. Yet, these key executives are ultimately more appraised on 

their companies’ profit performances than on their carrying out 

of Beijing’s foreign policy objectives. Put differently, the political economy of most Chinese energy investments in Africa is far 

more about “economy” than “political.”

132. Alex Vines, Thirst for African Oil, London, UK: London 

School of Economics, p. 20.

133. Besides China and aside from Middle East countries, other developing country players investing in Africa are from Russia 

(Gazprom, Lukoil, Rosneft), India (Oil India, ONGC), Malaysia 

(Petronas), and most recently, Indonesia (Pertamina and MedcoEnergi), Thailand (PTTEP), and Vietnam (PetroVietnam). See 

country profiles and “Natural Gas in Africa—The Frontiers of the 

Golden Age,” Ernst & Young, 2012, p. 8.

134. Tara Patel, “Total Sells Nigeria Oil Field to Sinopec for 

$2.5 Billion,” Bloomberg, November 19, 2012.

135. While the focus of this monograph is generally only on 

upstream exploration and production, China’s important role in 

Africa’s downstream oil and gas industry merits a footnote. Chinese firms have been building infrastructure across a wide range 

of oil-producing African countries—terminals, storage capacity, 

and, most critically, pipelines and refineries. In the case of refining 

capacity, the region’s crude distillation unit (CDU) capacity is expected to increase by about 10 percent in the period leading up to 

2015, with investment by Chinese investors dominating the proposed expansions. New Chinese-backed refineries are under construction in Chad and Niger, and have been proposed in Egypt, 

Sudan, and Nigeria. In addition, China’s CNOOC is one of the 

partners (with Tullow and Total) in the proposed new refinery in 

Uganda, which will process the country’s new crude oil production. China benefits not only from the profits of these contracts, 

but also the job creation and exports generating during construction of these projects. It also benefits to the extent that Chinese 

firms retain an ownership share in the refineries and pipelines. 

“H+K Strategies Advises CNOOC on $15.1 billion Acquisition of 

Nexen,” www.hkstrategies.com, February 28, 2013.
102

136. “Maurel Prom Reveals Approach for Gabon Oil Assets, 

Report Names Suitor Sinopec,” www.energy-daily.com, November 

1, 2012.

137. Ziling We et al., “Sinopec Said in Talks to Buy $1 Billion 

in Afren Assets,” February 1, 2013, available from bloomberg.com.

138. Available from csis.org/files/media/csis/pubs/csis_africa_review-energy_prepbub_draft.pdf.

139. “China Sonangol Shows Its Hand,” www.Africa-Asia-Confidential.com, December 2012.

140. “Corporate Social Responsibility,” from China Sonangol. 

Some observers would contend that there remains a significant 

gap between its stated commitment to CSR and the realities on 

the ground.

141. CNPC, de facto, trades as an ADR in New York through 

its main subsidiary, PetroChina. 

142. “Trends in U.S. and Chinese Economic Engagement,” 

GAO-13-199, Washington, DC: U.S. General Accountability Office, February 2013, p. 43.

143. Anonymous source, conference on China in Africa, 

Washington, DC, February 14, 2013.

144. Matthew Plowright, “China & Africa: Law of the Land,” 

September 6, 2011, available from www.emergingmarkets.org.

145. David Goldwyn, “Energy Security: The New Threats 

in Latin America and Africa,” Current History, December 2006, 

p. 442.

146. Goldwyn, “Pursuing U.S. Energy Security Interests in 

Africa,” p. 9.

147. China’s major natural gas pipeline for imports is the Central Asian Gas Pipeline (CAGP), which spans 1,130 miles, has a 

capacity of 1.4 tcf/y and brings natural gas to China from Turkmenistan, Uzbekistan, and Kazakhstan.
103

148. The case can be made that the boom in shale gas in the 

United States, along with anticipated new supplies in Africa, has 

also strengthened China’s negotiating hand with suppliers in its 

“near abroad,” such as Russia. In 2006, CNPC officials signed a 

Memorandum of Understanding with Russia’s Gazprom for two 

pipeline proposals, one from Russia’s western Kovykta gas field 

to northwestern China with a pipeline capacity between 1 and 

1.4 tcf/y by 2015. A second proposed route, called the Eastern 

pipeline, would connect Russia’s Far East and Sakhalin Island to 

northeastern China and would have 1.1 to 1.4 tcf/y of capacity. 

The countries have yet to agree on a price for the gas, however. 

Even before this, Russia had been trying for more than 10 years 

to negotiate long-term gas supply agreements with China that try 

to match the high prices that it had extracted from Europe for 

long-term contracts that pre-date the North American oil shale 

boom and the new gas discoveries in East Africa. The Chinese 

have dug their heels in, insisting on much lower prices, and know 

that time is now on their side. In March 2013, long-term natural 

gas contracts were at the top of the agenda in talks between Russian President Vladimir Putin and newly installed Chinese President Xi Jinping. The author believes that Russia may ultimately 

reach deals with China (and Japan) on more attractive terms than 

offered in the past because of this greater competition among 

suppliers. See “China—Background,” Country Analysis, on pipelines; and “Russia, China Inch Closer to Natural Gas Deal,” RiaNovosti, March 22, 2013, for details on the Putin-Xi meeting. 

149. Angelica Austin et al., “Energy Interests and Alliances: 

China, America, and Africa,” Policy Paper 7/2008, Brussels, Belgium: EastWest Institute, August 2008, p. i.

150. John Mitchell et al., “What Next for the Oil and Gas Industry?” London, UK: Chatham House, October 2012, p. 2.

151. Ibid., p. 20.

152. Christina Lin, “China’s Strategic Shift Toward the Region of the Four Seas: The Middle Kingdom Arrives in the Middle 

East,” Middle East Review of International Affairs, Vol. 17, No. 1, 

Spring 2013, p. 33.
104

153. Lieutenant Colonel Daniel J. Kostecka, “A Bogus Asian 

Pearl,” U.S. Naval Institute Proceedings, April 2011, pp. 50-51. 

154. David Pilling, “Pipeline marks scramble for Myanmar,” 

Financial Times, January 30, 2013.

155. “The Diversified Employment of China’s Armed Forces,” 

State Council, April 2013, available from news.xinhuanet.com/english/china/2013-04/16/c_132312681.htm.

156. Ibid., p. 33, Note: The original Chinese, 远海 (yuanhai), 

has also been translated as “distant seas.”

157. Robert D. Kaplan, “China’s Two-Ocean Strategy,” Chap. 

II, Abraham Denmark and Nirav Patel, eds., China’s Arrival: A 

Strategic Framework for a Global Relationship, Washington, DC: Center for a New American Security, September 2009.

158. Ibid., p. 51, makes the following historical analogy with 

the United States that is useful for understanding the importance 

of the Malacca Strait to China: 

Just as the U.S. Navy moved a century ago to control the 

Caribbean Basin, so must the Chinese Navy move, if not to 

control, then to at least . . . become as dominant as the Americans in these seas: for the Malacca Strait can be thought of 

akin to the Panama Canal, an outlet to the wider world.

159. Lin, p. 32. Note: Lin has a figure of 80 percent, while Kaplan, p. 49, indicates it is as much as 85 percent.

160. Regarding 2), it is notable that India’s naval forces in the 

Indian Ocean are becoming much more powerful and already include “state-of-the-art aircraft carriers, nuclear submarines, and 

other surface combatants.” See Jonathan Holslag, “China’s New 

Security Strategy for Africa,” Parameters, Carlisle, PA: U.S. Army 

War College, Summer 2008, p. 26. 

161. Daniel J. Kostecka, “Places and Bases—The Chinese Navy’s Emerging Support Network in the Indian Ocean,” Naval War 

College Review, Winter 2011, Vol. 64, No. 1, pp. 68-70.
105

162. Wilson Chau, “Seychelles Invites China to Set Up Naval 

Base,” San Francisco, CA: New Pacific Institute, December 7, 2011.

163. Loro Horta, “China Turns to the Sea: Changes in the 

People’s Liberation Army Navy Doctrine and Force Structure,” 

Comparative Strategy, Vol. 31, No. 393, p. 400.

164. Jorge Benitez, “International Herald Leader,” Chinese 

state-run newspaper under Xinhua News Agency, China Defense 

Mashup, as translated in “China Paper Urges PLA Navy to Build 

Overseas Military Bases,” www.acus.org, January 19, 2013.

165. James R. Holmes et al., “China and the United States in 

the Indian Ocean—An Emerging Strategic Triangle?” Naval War 

College Review, Summer 2008, Vol. 61, No. 3, p. 42.

166. Kaplan, p. 57.

107

APPENDIX I

AFRICAN OIL AND GAS EXPLORATION 

AND PRODUCTION—

COUNTRY PROFILES LISTED ALPHABETICALLY

Algeria.

Depending on information source, in 2010, Organization of Petroleum Exporting Countries (OPEC) 

member Algeria was either the world’s 8th or 10th 

largest producer of natural gas and 16th largest producer of crude oil. The country accounted for 2.5 percent and 2.0 percent of world natural gas and crude 

oil output, respectively. In 2010, Algeria was Africa’s 

leading producer of natural gas and third or fourthranked producer of crude oil after Nigeria and Angola, and ahead or behind of Libya, depending on information source.1

 Algeria held 159 trillion cubic meters 

(tcm) of proven natural gas reserves, 2.4 percent of the 

world’s total, the 10th largest reserves in the world, 

and second largest in Africa after Nigeria. Algeria had 

12.2 billion barrels of proven crude oil reserves, or 0.9 

percent of the world’s total.2

 Reserves were the third 

largest in Africa behind Libya (47.1 billion barrels of 

oil [bbbl] and Nigeria (37.2 bbbl). In 2011, Algeria’s 

crude oil exports were 750,000 barrels per day (bpd), 

of which 40.5 percent went to North America, mainly 

to the United States.3

Of Algeria’s current hydrocarbon output, 75 percent comes from two fields: Hassi Messaoud and Hassi R’Mel. Algeria’s NOC, Sonatrach, was responsible 

for 72 percent of hydrocarbon output; international 

oil companies (IOCs) working under Production 

Sharing Agreements (PSAs) were responsible for the 

remainder. These IOCs included U.S. firm Anadarko 
108

(the largest foreign producer, with 500,000 bpd),4 a 

number of European IOCs, and other emerging market NOCs, including China’s CNOOC,5

 CNPC,6 Russia’s Gazprom,7

 and Thailand’s PTTEP.8 The U.S. firm 

ConocoPhillips announced in December 2012 that it 

would sell its Algerian operations to Indonesia NOC 

Pertamina for $1.75 billion.9

Algeria’s unfavorable 2005 hydrocarbon law and 

a 2006 presidential decree have dampened the enthusiasm among IOCs for investment in the country’s oil 

and gas sector, contributing to a 20 percent drop in hydrocarbon production over the last 5 years.10 Because 

of meager interest, the Algerian government only 

awarded three of 10 permits offered in a 2010 round, 

including an award to Spain’s Repsol, and two of 10 

in another round in 2011, with only France’s Total a 

winner among international majors. In January 2013, 

Algeria’s parliament approved amendments to the 

law that cancelled a windfall tax on foreign firms and 

replaced it by a “complementary tax on results.” It 

also offered incentives to foreign firms to invest in unconventional resources.11 The government announced 

that it plans a new round of bidding on permits in 

2013, following the adoption of the new hydrocarbon 

amendments.12 Some observers, however, remain pessimistic that these amendments will be able to turn 

around declining foreign investment and production 

because of regulatory instability and Algeria’s low 

ranking—148 out of 183 nations—in the World Bank’s 

“Doing Business” index.13 A number of fields operated by Sonatrach are in steep decline, including Hassi 

Berine South (with Anadarko) and Rhourde Oulad 

Jemmah (with Australia’s BHP Billiton).14

Another serious problem is that Algeria’s domestic demand for oil and gas is consuming an increas-
109

ing proportion of production. Domestic oil consumption rose from 26 percent of production in 2005 to 40 

percent in 2010; domestic consumption of natural gas 

rose from 19 percent of production to 29 percent. A 

1.5 percent annual increase in population, a rapid increase in the number of cars, and artificially low domestic prices were all factors behind this increased 

domestic demand.15 Without increased investment, 

these trends led a Chatham House study to warn 

that Algeria would have no oil available to export after 2023;16 a more recent study put this date between 

2018 and 2020.17 Attracting foreign investment is thus 

a critically important issue for the Algerian government, which depended on the hydrocarbon sector accounting for 36 percent of the gross domestic product 

(GDP), 60 percent of budget revenues, and over 97 

percent export earnings in 2010.18

Nevertheless, other observers are more optimistic, 

noting new production projects. Sonatrach made 27 

oil and gas discoveries in 2010, while Gazprom and 

Germany’s Ruhrgas made one discovery each. Thirteen discoveries were in the Berkine Basin in eastern 

Algeria, 10 in the Illizi Basin, 4 in the central region of 

the Amguid Massaoud Basin, and 2 in the Oued Mya 

Basin.19 At the end of 2012, Repsol announced a new 

gas find at the Tihalatine South well in the Illizi Basin, 

a new find at the Sud-Est Illizi block in April 2013,20

and plans four new wells.21 Repsol also has a major 

presence in Tinfouye, Tabenkort, and Tifernine. The 

Menzel Ledjmet East project led by Italy’s ENI started 

production in February 2013.22 The UK’s BP and Norway’s Statoil have a joint venture in two fields, including Salah Gas, which is expected to start production 

later in 2013.23 The U.S. firm Hess (49 percent partner 

with Sonatrach) is investing in the Gassi El Agreb 
110

Redevelopment Project to boost production in three 

long-standing oil fields.24 Sonatrach is also banking on 

production of 100,000 bpd at the El Merk oil hub (with 

partner Anadarko and where production started in 

May 201325); on Bir Seba (PetroVietnam,26 36,000 bpd); 

on Mezel Ledjmet (formerly ConocoPhillips, 300,000 

bpd); and on the Illizi Basin in the southeast (Russia’s 

Rosneft, 38,000 bpd).27

China’s CNOOC, along with partner Sonatrach 

and Thailand’s PTTEP, successfully discovered crude 

oil in September 2012 in the fourth and fifth exploration wells in the Hassi Bir Rekaiz project.28 China’s 

CNPC has acquired the exploration licenses for Blocks 

102a/112 in the Chelif Basin in northern Algeria (75 

percent operator; 25 percent Sonatrach), Block 350 

of the northwestern Oued Mya Basin in the north of 

the Sahara Desert (75 percent operator; 25 percent 

Sonatrach), and Block 438b, also in the Oued Mya Basin (100 percent).29

The Algerian government which has a 5-year, 

2012-16 plan to invest $80 billion in its energy sector,30 has been constructing new liquefied natural gas 

(LNG) facilities and intends to increase its exports of 

natural gas to 100 bcm by 2015, up 60 percent from 

2012 levels.31 Algeria is in the process of developing its 

Southwest Gas Project, which includes the 102 billion 

cubic feet per year (bcf/y) Reggane Nord fields led by 

Spain’s Repsol (expected production of 8 million cubic meters per day (m3/d) by mid-2016), the 56 bcf/y 

Timimoun project led by France’s Total (with production starting in 2016),32 and the 159 bcf/y Touat project 

led by France’s GDF Suez.33

A Russian joint venture of Rosneft and Stroytransfaz (jointly holding 60 percent, with Sonatrach holding 40 percent) operates Block 245-S in southern Algeria.34 The partners are delineating the reservoir at 
111

three previously made discoveries in east and west 

Takazet and north Tisselit.35

Angola.

Although Angola became an OPEC member in 

1997, it has not always followed the organization’s 

production demands. In 2009, for example, Angola’s 

OPEC production target was 1.51 million bpd, but the 

country actually produced 1.8 million bpd. Technical 

and maintenance problems have plagued some of Angola’s deepwater fields for years and will continue to 

limit Angola’s crude oil production in the short term. 

Nonetheless, the International Energy Agency (IEA)

still anticipates Angolan crude oil output to increase 

gradually over the next 2 years as new deepwater 

production more than offsets chronic maintenance‐

related declines.36 The government, which depended 

on oil exports for 98 percent of government revenues 

in 2011, plans to boost oil and natural gas production 

over the coming decade.37 Crude oil accounted for 46 

percent of Angola’s GDP and 94 percent of exports in 

2011. The United States and China are Angola’s main 

markets for crude oil.38

Crude Oil.

Angola had proved reserves of 9.5 billion barrels 

of crude oil, the second-largest in sub-Saharan Africa 

after Nigeria and 18th in the world. Recent exploration suggests that Angola’s reserves may be larger 

than originally estimated, and foreign investors are 

also beginning to consider that some onshore opportunities may be economically viable. BP put Angola’s 

recoverable reserves at 13.5 billion barrels at the end 

of 2011.39
112

LNG. 

Angola had proved reserves of natural gas of 10.95 

trillion cubic feet (tcf), the fifth-largest in Africa. While 

91 percent of Angolan natural gas was re-injected into 

the country’s oil fields in 2011 to aid recovery—or 

simply flared off—Angola is making efforts to produce and market its natural gas, starting with the 

Chevron-led Soyo plant, which has a capacity of 5.2 

million tons per year of LNG, 40 with start-up planned 

for June 2013.41 While gas production had originally 

been scheduled for shipment to Mississippi, the shale 

gas boom in the United States has made this unfavorable, and Angola is now targeting consumers in Europe and Asia. 42

Angola has three main sedimentary basins: the 

Congo to the north, also straddling offshore and onshore the coasts of the Democratic Republic of Congo 

(DRC) and Congo (Brazzaville); Kwanza, straddling 

the central coastal region; and Namibe, straddling the 

coast in the south and extending into Namibia. All 

three basins have the pre-requisites for hydrocarbons, 

but Namibe has not yet yielded them in commercial 

quantities.43 In 1955, the first onshore commercial discovery was made at the Benfica Field in the Kwanza 

Basin. In 1966, the first offshore commercial discovery 

was made at the Limba Field in the Lower Congo Basin. During much of the 27-year civil war starting at independence from Portugal in 1975 and ending in 2002, 

exploration activity onshore was restricted. However, 

deepwater exploration began in 1993, leading in 1996 

to the first deepwater commercial discovery, the huge 

Girassol Field in the Lower Congo Basin.44
113

Successful exploration in Angola’s pre-salt formations continues to drive optimistic oil production 

forecasts for the country. Recently, there have been 

new discoveries made on several oil fields in Angola, 

including at offshore fields Greater Plutonia, PSVM, 

Girassol, Pazflor, CLOV, Chissonga, and onshore 

in Cabinda South.45 Oil exploration and production 

in Angola mainly occur offshore, divided into three 

bands: Band A, with shallow water Blocks 0-13; Band 

B with deepwater Blocks 14 to 30; and Band C with ultra-deepwater Blocks 31-40.46 For example, Italy’s ENI 

made its ninth discovery in deepwater Block 15/06 

in March 2013.47 Oil majors spent $3.55 billion acquiring acreage in offshore Kwanza Basin in 2011. Spain’s 

Repsol has 15 licenses, three of which were awarded 

in December 2011 for Kwanza.48 This basin is said to 

hold the most potential because, 122 million years ago, 

it adjoined the Campos Basin, which is Brazil’s largest 

petroleum province.49

Angola will remain the top destination in Africa 

and the Middle East for offshore drilling over the next 

few years. One consultancy estimated that expenditures on offshore drilling would rise to $6.67 billion 

in 2016, with Nigeria and Egypt a distant second and 

third at $2.26 billion and $1.52 billion respectively.50

Although crude oil production in Angola slipped to 

1.79 million bpd in 2011, the government is targeting 2 

million bpd production levels by 2014. 

The large majority of current production is made 

offshore by three majors: France’s Total, with 648,200 

operated bpd, U.S. firm Chevron with 434,000 operated bpd, and ExxonMobil with 394,300 operated 

bpd.51 Total’s production mainly comes from Blocks 

0 (offshore Cabinda) and Block 17 (which has three 

producing zones, as well as Girassol, Dali, and Paz-
114

flo. Another field, CLOV, is expected to start in 201452

and reach production of 160,000 bpd.53 For Block 17, 

Total is operator with a 40 percent share along with 

Norway’s Statoil (23.33 percent), 54 ExxonMobil (20 

percent),55 and BP (16.67 percent).56

Chevron operates Block 0 in the Congo Basin in 

Cabinda, where the mighty Congo River deposited 

huge amounts of sediment along with vegetative 

matter that eventually turned into oil over geological time.57 Although some offshore fields in Cabinda 

enclave are aging, others are coming online. In February 2013, Chevron approved the $5.6 billion Mafumeira Sul project in Block 0 (Cabinda), including 50 

wells and 75 miles of subsea pipelines. The project, 

for which Chevron as operator will have a 39.2 percent share and partner with Sonagol, Total, and ENI, 

is expected to see first oil in 2015 and build toward 

peak total daily production of 110,000 bpd and 10,000 

barrels of liquid petroleum gas (LPG) commercialized 

through the Angola LNG plant in Soyo. Mafumeira 

Norte, the initial, northern development of this field, 

achieved first oil in 2009 and currently produces more 

than 40,000 bpd.58 Other than at Block 0, Chevron has 

three other concessions in Angola: Block 2 offshore 

northwest Angola, Block 14 in deepwater, and onshore Fina Sonagol Texaco.59

As noted earlier, China’s Sinopec and CNPC hold 

non-operator shares in several offshore blocks in Angola, the most important of which may be joint venture 

China Sonangol’s 27.5 percent share in Block 17/06 

and 20 percent share in Block 32.60 China Sonagol also 

has non-operator interests in six other oil blocks in 

Angola (3/05, 3/05A, 15/06, 18/06, 18, and 31).61 U.S. 

firm Marathon owns a 10 percent interest in Blocks 31 

and 32.62 U.S. firm ConocoPhillips acquired, in Janu-
115

ary 2012, 30 percent operator interests in two deepwater offshore licenses for Blocks 36 (with partners 

Sonagol, 50 percent, and China Sonagol, 20 percent) 

and 37 (partners Sonangol 50 percent and Spain’s Repsol 20 percent). ConocoPhillips expects first drilling in 

these blocks in 2013-14.63

A number of other smaller IOCs are also active in 

Angola. Denmark’s Maersk Oil made a discovery in 

offshore Congo Basin Block 16 in September 2012.64

U.S. firm Cobalt International has sought pre-salt 

properties in West Africa, and has acquired operator 

rights to Angola’s offshore blocks nearshore 9, and 

deepwater 20 and 21.65 Cobalt has a four-well exploratory well program starting in the Lontra Prospect in 

Block 20,66 with the first well to spud in 2013 2Q. Cobalt’s two exploratory wells in Block 21 confirmed the 

presence of a mound reservoir, but failed to flow oil.67

Onshore. 

The government plans to open another licensing 

round in 2013 for the country’s onshore blocks in the 

pre-salt Kwanza Basin68 and the Lower Congo Basin.69

Fifteen blocks will reportedly be offered, all located 

within close distance of the Atlantic shore rather 

than far into the interior. Most of Angola’s earliest oil 

discoveries were made onshore in the 1950s, but remained lightly explored due to security concerns that 

decades later are finally receding. At present, Italy’s 

ENI plans to drill two exploration wells in Cabinda’s 

onshore North block starting in mid-2013.70
116

Shared Development Areas: Progress with Congo, 

Agreement with DRC Soon? 

In March 2012, Angola and Congo (Brazzaville) 

signed an agreement to jointly exploit the Lianzi 

cross-border oil field on their mutual border and share 

profits equally.71 Following this, Chevron announced 

in July 2012 that it would proceed with five partners, 

including Angola and Congo National Oil Companies 

(NOCs), in the development of the Lianzi Field, via 

a tieback to its existing BBLT platform in Angola’s 

Block 14.72 The boundary dispute with the DRC is 

more intractable, but observers hope the Lianzi deal 

will inspire an agreement on shared development. In 

September 2012, the DRC Minister of Hydrocarbons 

predicted that the two countries would come to an 

agreement over the so-called Common Interest Zone 

in 6 months, but that shared production of any resources was still some time off.73

Benin.

Benin’s estimated oil and gas reserves are a modest 4-8 million barrels, and current interest by Western 

majors remains limited.74 Sillenger Exploration, which 

has a contract with Benin’s government to attract 

foreign investment in natural resources, estimated 

in September 2011 that Benin had five billion barrels 

of oil—i.e., roughly 1,000 times greater than proven 

reserves.75 Benin’s offshore sedimentary basin, also 

known as the Dahomey Basin, is part of the larger 

Transform Margin of the Gulf of Guinea extending 

from the Keta Basin in eastern offshore Ghana eastward through Togo and Benin to the Mont Okitipupa 

Basin in Nigeria.76 The Dahomey Basin in Benin also 
117

includes the Hihon-1 and Fifa-1 discoveries (drilled by 

Kerr-McGee, which was later acquired by Anadarko). 

Benin’s government has designated 12 offshore 

blocks, but the only producing field, Seme, in Block 

1, produced a maximum of 8,000 bpd in 1982 tapered 

down to 1,900 bpd,77 and was closed and restarted 

by multiple operators.78 The latest of these operators 

is Nigeria’s South Atlantic Petroleum (SAPETRO), 

which plans to drill three production wells in 2013 4Q 

to produce a peak of 6,000 bpd and drain the field.79

Addax Petroleum, a Canadian subsidiary of China’s 

Sinopec, has a 50 percent interest in Block 1.80 The 

UK’s Century International is attempting to farm out 

its interest in Block 2, citing estimates of four billion 

bbls OOIP in the Gbenonko East and West prospects.81

In 2005, the Korea National Oil Corporation had interests in two offshore blocks and drilled in Block 2. 

South Africa’s Signet acquired a 90 percent interest in 

Block 3 in 2011.82 Brazil’s Petrobras acquired in 2011 

a 50 percent share of offshore block 4; the remainder 

is owned by Brazil’s Lusitania Petroleum. If 3D seismic confirms potential, this Brazilian joint venture 

plans three exploratory wells.83 After commissioning 

3D seismic data in 2011, Nigeria’s Oranto is seeking 

an experienced deepwater operator to farm-in part 

of its 100 percent interest in deepwater Blocks 5 and 

6. Oranto also has a 100 percent interest in Block 8 

which, like Blocks 5 and 6, it acquired after direct negotiations with the Benin government. Onshore, a tar 

belt in Benin’s coastal region has been sourced to an 

offshore source of hydrocarbons, but is apparently not 

being actively explored.84
118

Botswana.

Botswana has an unknown quantity of natural gas 

deposits in the Kalahari Karoo Basin and the Kgalagadi (Kalahari) Desert. Current exploration efforts 

largely focus on coal-bed methane.85 A joint venture 

between Australia’s Origin Energy and South Africa’s 

Sasol began in June 2012 the first part of a three-year 

program to explore for coal-bed methane in three licensed areas.86 The program also included an extensive drilling program. Origin’s CEO Grant King said 

that “The delineation of a large [coal-bed methane] 

resource in Botswana could be used for power generation and liquid fuels production in southern Africa.”87

A second firm, Australia’s Sunbird Energy, has eight 

permits for exploration in the Kalahari Karoo Basin 

in northern Botswana, approximately 100 kilometers 

(km) south of the Wankie coalfield in Zimbabwe. The 

firm planned an aeromagnetic survey in 2012 followed 

by a two core-hole drilling program.88 Australian junior Tlou Energy set a stock listing in February 2013 to 

raise funds to a coal-bed methane appraisal program 

in Botswana.89 Australia’s Magnum Gas & Power has 

prospecting licenses in the Nata region over the Ngwasha Basin and the Central Project over the Mmashoro 

Basin.90 (See also sections on Mozambique, Namibia, 

South Africa, and Zimbabwe for more on coal-bed 

methane in southern Africa.)

Some oil exploration companies have started 

to make bets that the East Africa Rift System has a 

branch that travels through Zambia, Botswana, and 

northeastern Namibia.91 South Africa’s SacOil obtained three petroleum prospecting permits in Botswana, and Magnum Gas & Power has a petroleum 

and natural gas exploration license in the Ngamiland 

and Central districts.92
119

Burkina Faso.

There are no known hydrocarbons in Burkina Faso.

Burundi.

Burundi’s Minister of Energy and Mines, Come 

Manirakiza, announced in September 2012 that hydrocarbons had been found in his nation based on 

“geochemical and petrochemical analyses of surface 

samples taken from Lake Tanganyika and the Rusizi 

plain.”93 Burundi has designated four blocks for oil exploration: onshore Block A in the Rusizu Basin, attributed to Nigeria’s A-Z Petroleum, and Blocks B-D running north-to-south in Burundian territorial waters on 

Lake Tanganyika. Blocks B and D are held by the UK’s 

Surestream Petroleum, while Block C is held by Nigeria’s Minergy, which in turn is 87.5 percent owned 

by South Africa’s Signet Petroleum.94 Burundi’s blocks 

are located in the western branch of the Tanganyika 

Graben that, in turn, is part of the larger East African 

Rift System. 

Aeromagnetic studies in 1982 suggested that Burundi may have hydrocarbon resources.95 Some experts view Lake Tanganyika’s geology as analogous 

to the tertiary rift system at Lake Albert to the north 

between DRC and Uganda, where large oil discoveries have been made.96 Surestream plans to complete 

seismic studies in 2014-15, with drilling carried out 

afterwards.97

Cameroon.

Cameroon has two main basins with proven 

hydrocarbons: 
120

• offshore Rio de Rey, between the northwest

edge of Cameroon and Equatorial Guinea’s 

Bioko Island to the south, where 89 percent of 

commercial oil deposits are located; and 

• offshore and onshore in Douala/Kribi-Campo

in the southwestern coast, where 11 percent of 

oil deposits are located.98

Rio del Rey is part of the southern margin of the 

larger Niger Delta Basin.99 Two other basins with possible hydrocarbons are onshore: the Mamfe Basin in 

the southwest,100 and the Logone-Birni Basin in northeast.101 There has been significant, recent exploration 

in both the Rio del Rey and the Douala/Kribi-Campo 

Basin, with discoveries made of oil and/or gas/condensate.102 In 2010, Cameroon’s proven oil reserves 

were a modest 200 million barrels; its proven natural 

gas reserves were 4.77 tcf.103

While Cameroon’s oil production has been declining since 1985, when production peaked at 181,000 

bpd,104 the government announced in January 2012 

that it expected production would rise about 59 percent by the end of 2012 because of the development of 

new fields. The Cameroon government also launched 

in January 2013 a new licensing round for five onshore 

and offshore blocks in three areas: Lungahe, Bomana, 

and Dissoni in the Rio del Rey Basin, Kombe-Nsepe 

in the Douala/Kribi-Campo Basin, and Manyu in the 

Mamfe Basin.105

A major player in Cameroon is Anglo-French 

Perenco, which purchased the local upstream assets 

of France’s Total in 2011. At offshore Ebome Marine, 

Perenco has offset the natural decline of these fields by 

an aggressive program of satellite developments. Similarly, Perenco is optimizing production at its Moudi 
121

field with an active work-over program with ESP, gas 

lift, and sand control. Perenco is moving forward with 

its plans to develop the Dissoni Nord discovery made 

in 2005 and expects to stabilize operated production 

at 40,000 bpd106—a large fraction of Cameroon’s average production of 63,000 bpd in 2012.107 The firm is 

also pursuing an ambitious exploration program in 

Kombe-Nsepe.108

China’s Sinopec, through its Addax subsidiary, 

has a 37.5 percent share in Dissoni. Addax is also the 

100 percent operator of the Iroko license area, located 

approximately 30 km offshore, the 60 percent operator 

of the Ngosso license area in Rio del Rey Basin, and 

the 40 percent operator in Lokele’s Mokoko Abana 

Field. The firm also has 24.5 to 32.25 percent shares in 

eight fields in Lokele (2) and Rio del Ray (6) operated 

by Perenco.109 China’s Sinopec bought in November 

2011 an 80 percent stake in Shell Oil’s Cameroon subsidiary, with the 20 percent remainder owned by NOC 

SNH. This gave China stakes in 12 offshore blocks in 

Cameroon.110

The UK’s Bowleven, acting as operator with a 75 

percent share, and Vitol, a Dutch oil trader with a 25 

percent share, have PSCs for three shallow offshore 

blocks, MLHP 5, 6, and 7, collectively known as the 

Etinde Permit, running northwest to southeast along 

the coast between the Rio del Rey and Douala Basins 

and bordering Equatorial Guinea’s Bioko Island. From 

January 2012111 to February 2013,112 Bowleven made a 

series of commercial discoveries during well drilling 

in MLPH 5 and 7.113 Bowleven also has 100 percent 

shares in OLHP 1 and 2, two onshore blocks near 

Mt. Cameroon in the Bomono Permit Area, which is 

an onshore extension of the Douala Basin,114 and was 

preparing for a first exploratory well in early-2013. 
122

In March 2012, Bowleven was also engaged in discussions with the Cameroon government about the 

construction of a fertilizer plant using natural gas.115

Switzerland’s Glencore is the 90 percent operator of 

the Matanda offshore block and plans two exploratory wells for 2013. (Bermuda-based AFEX owns the 

remaining 10 percent.)116 Vietnam NOC PetroVietnam 

has a license for the Bomana offshore block.117

In 2013 2Q, the U.S. firm Kosmos drilled its SIPO1 exploratory well in the Liwenyi Prospect in its 100 

percent operated Ndian River Block, which is part of 

the Niger River Delta abutting the border with Nigeria 

to the north and bordering the Rio del Rey Basin to the 

south. However, the firm found evidence of a working 

petroleum system, but did not encounter commercial 

reservoirs.118 The company’s second 100 percent operated onshore block, Fako, borders to the southeast of 

the Ndian River block and straddles the Rio del Rey 

and Douala/Kribi-Campo Basins.119 Kosmos acquired 

the second block in 2012 and will carry out a six-year 

program including one exploratory well.120

The U.S. firm Murphy Oil has operator interests 

in two offshore blocks, 100 percent in Mer Profonde 

Nord and 50 percent in Mer Profonde Sud, the latter 

with the UK’s Sterling Energy holding the remaining 

50 percent.121 Murphy drilled an unsuccessful well in 

Mer Profonde Nord in November 2012,122 but plans 

to drill up to two more wells in 2013. In 2011, Murphy also purchased a 50 percent operator interest 

from Sterling for the Ntem deepwater concession in 

the Southern Douala/Rio Muni Basin adjacent to the 

northern maritime border of the Rio Muni province 

of Equatorial Guinea. (Sterling retains the remaining 

50 percent share.) Operations in the Ntem concession 

are currently suspended under the force majeure pro-
123

visions of the license owing to an overlapping maritime border claim between Cameroon and Equatorial Guinea, but both countries are working to resolve 

their dispute.123

The U.S. firm Noble Energy has 50 percent operator interests in the offshore YoYo mining concession 

and Tilapia exploration block,124 both in the Douala/

Kribi-Campo Basin bordering on the coast to the east 

and Equatorial Guinea’s maritime border to the west. 

(Malaysia’s Petronas holds the remaining 50 percent 

interest.125) Noble said these Douala Basin interests 

gave it “upside potential;”126 nevertheless the firm 

drilled a dry hole in October 2012 in Tilapia.127

Exploration in Contested Bakassi.

Dana Petroleum, a subsidiary of the Korean National Oil Company (KNOC), is 55 percent share operator of the Bakassi West Block in the northern Rio Del 

Rey Basin, partnering with two Canadian firms, Madison Petrogas (35 percent share) and SoftRock Oil and 

Gas (10 percent). 128 The Bakassi region is considered 

to be rich in oil and gas, but has had no modern exploration due to a past territorial dispute with Nigeria, 

which was settled in Cameroon’s favor by internationally sponsored treaties in 2002 and 2006.129 As part of 

the reconciliation between the two countries, the UN 

Special Envoy for West Africa, the Algerian Said Djinnit, in 2011 called on both countries to jointly develop 

Bakassi’s oil reserves. A senior Nigerian official called 

on China’s Addax Petroleum to play a leading role in 

joint development since it already operates in both Nigeria and Cameroon,130 but it remains to be seen how 

interested Cameroon is in joint development. 
124

Onshore Northeast Cameroon. 

China’s Yang Chang Logone Development Holding Co. Ltd. acquired two blocks, Makary near Lake 

Chad, and Zina, about 20 km north of the Waza 

Park.131 In January 2013, this Chinese firm temporarily suspended its exploration operations in the blocks, 

which flank Chad’s southern oil wells in Doba, after 

devastating floods.132

Monetizing Natural Gas.

Gas reserves in Cameroon are substantial, but had 

not been exploited previously because of a limited 

market. The Cameroon government, eager to monetize 

its 3.5 tcf in technical gas reserves, began a feasibility 

study for an LNG plant in 2009, with Gaz de France 

Suez,133 whose President predicted that Cameroon 

could become an important actor in commercial natural gas by 2018.134 The plant, which would be located 

30 km south of Kribi and connected to the national gas 

pipeline network, would have an annual capacity of 

3.5 million tons for its first train and use natural gas 

that is currently flared.135 The Cameroon government 

also wishes to build a second LNG plant at Douala.136

Perenco signed Cameroon’s first gas sales agreement, 

in which its offshore Sanaga field will supply gas to 

an onshore power plant.137 The United Kingdom’s 

(UK) Victoria Oil and Gas is working to commercialize the natural gas reserves on its Logbaba permit by 

signing approximately 20 gas sales agreements138 with 

industrial customers in Douala, including breweries 

and food processing plants, and anticipates daily sales 

volumes reaching 12 million standard cubic feet per 

day (mmscf/d) by December 2013, with an estimate 
125

of total gas demand in excess of 100 mmscf/d within 

5 years.139

Chad-Cameroon Pipeline.

Chad and Cameroon have been exporting oil from 

the Doba crude oil fields in southern Chad via a 1,000-

km pipeline through neighboring Cameroon to the 

port of Kribi, on the Gulf of Guinea. The pipeline is 

one of the largest U.S. investments in sub-Saharan 

Africa, estimated to cost $4.4 billion when it was constructed in 2000, and the majority interest is held by 

ExxonMobil and Chevron.140

Cape Verde.

In 2006, Angola NOC Sonagol had expressed an 

interest in oil and gas exploration in Cape Verde’s 

archipelago and suggested that oil and gas reserves 

discovered in neighboring Mauritania could stretch as 

far as Cape Verde. Cape Verde’s Prime Minister Jose 

Maria Neves indicated in July 2010 that his country 

was hopeful that oil and gas might be found in deepwater pre-salt layers in its Exclusive Economic Zone 

(EEZ).141 Following his signing of an agreement with 

visiting Brazilian President Luis Inacio Lula in 2010, 

Petrobras signed an accord for exploration offshore 

Cape Verde.142 Chinese and Senegalese entities also 

expressed an interest in exploration in Cape Verde.143

Central African Republic.

In collaboration with Sudanese partners, China’s 

CNPC restarted oil exploration in April 2011 in five 

potential fields in Doba Dosea Salamat region in 
126

northeastern Central African Republic (CAR) near the 

border with Chad. CAR reportedly has a proven oil 

potential of one billion barrels, with some possibility 

of five times this much.144 In 1993, Western Geophysical reported that there exists a common Chad-Central 

African Basin that straddles the frontier between CAR 

and Chad and is associated with the Central African 

Rift system. Oil was discovered in Chad in the 1960s, 

and the development of oil fields near the Chadian 

border with CAR started in 2000. CNPC identified 

four promising sub-basins: Bagara (between CAR, 

Sudan, and South Sudan), Doseo (between CAR and 

Chad), Salamat (CAR), and Doba/Bangor (Chad).145

Despite prospects for oil discovery, petroleum development and production in the CAR will likely be 

held back by the country’s political instability. There 

have been a series of civilian and military governments since independence in 1960, and the government of the President Francois Bozize, who himself 

came to power in a military coup in 2003, did not fully 

control the countryside, particularly in the northern 

and central parts of the country, where several rebel 

groups and the Lord’s Resistance Army operate.146

Rebel groups drove Bozize from power on March 23, 

2013,147 and elected self-proclaimed President Michel 

Djotodia as interim head of state.148

Chad.

Today, Chad has proven reserves of 1.5 billion barrels with excellent prospects to increase this figure.149

Chad shares with its neighbors three sedimentary basins known for oil and gas potential: 
127

1) the Koufra–Erdis Basin in the north shared with 

Libya; 

2) the Chad Basin in the center-west shared with 

Niger, Northern Nigeria and Cameroon; and,

3) the Sud Basin in the south shared with CAR and 

South Sudan. 

Oil exploration began in Chad in the 1950s and led 

to discoveries in the 1960s before developments were 

blocked by political instability. In the 1990s, discussions between the World Bank, the Chad and Cameroon governments, and a private consortium led to 

a decision to build simultaneously in 2000, the “Esso 

Chad Doba Exploitation” and the Doba-Kribi pipeline.150 Eighty-five percent of this pipeline is located in 

Cameroon.151 Since 2003, ExxonMobil, Chevron, and 

Malaysia’s Petronas, through two consortia in Chad 

and Cameroon, have been exporting oil from the Doba 

crude oil fields in southern Chad via a 1,000-km pipeline to Cameroon’s Kribi port, on the Gulf of Guinea. 

Chad’s major oil fields are the Bolobo, Kome, and 

Miandou in the Doba Basin, which are estimated to 

contain reserves of 900 million barrels.152 ExxonMobil’s oil production in Chad peaked at 126,200 bpd 

in 2010,153 and averaged 115,000 bpd in 2011. (ExxonMobil’s operator share in the seven fields in Doba154

was 40 percent, with Petronas holding 35 percent and 

Chevron 25 percent.)155 The company drilled 69 additional production wells in 2011.156

New companies, including China’s CNPC and Canada’s Griffiths Energy International (which is changing its name to Caracal), have also reached agreement 

with the Chad and Cameroon entities to use the pipeline to export oil from their fields157—making the author wonder if there is not a risk of exceeding the pipe-
128

line’s current capacity. Griffiths hopes to complete as 

early as 2013 2Q a 111-km connection pipeline to link 

its Badila and Mangara fields to the export pipeline.158

Griffiths successfully drilled two exploratory wells—

Badila-1 and -2 in May 2012 and January 2013,159 and 

commenced drilling of Mangara-4 in March 2013.160

Griffiths, which sold a 25 percent interest in the fields 

to Switzerland’s Glencore International in September 2012161 to finance the development of Badila and 

Mangara,162 became embroiled in a bribery scandal 

in January 2013 when Griffiths pled guilty in Canada 

to having bribed Chadian officials in order to gain its 

production sharing contracts (PSCs) in 2011.163

The U.S. firm ERHC won 100 percent shares in 

three blocks in 2011, two of which—BDS 2008 and 

the northern half of Chari Ouest III—fall on the north 

flank of the Doba/Doseo Basin in southern Chad, 

where ExxonMobil and others have discovered 1.29 

billion BOE.164 The third block, known as Manga, is in 

northwest Chad, adjacent to the Niger border.165 The 

Canadian firm Simba Energy won 100 percent shares 

in three blocks in September 2012, two of which—

Chari Sud I and the southern half of Chari Sud II, both 

bordering with the CAR—are also in the Doba/Doseo 

Basins south of Mangar and Badila, where their large 

proven reserves are located.166 The third block, Erdi 

III, is located in northeastern Chad near the Libya border.167 The Doba/Dosea Basins are part of the West 

and Central African Rift Systems that extend across 

central Africa from Nigeria to Kenya to Sudan.168

Earlier, the Chadian government tried to boost 

the potential of other fields through diplomatic channels. While Chad was one of the last countries in Africa to keep diplomatic ties with Taiwan authorities 

(and not the Peoples’ Republic of China),169 Taipei’s 
129

NOC, China Petroleum Corporation, actively engaged 

in oil exploration. Even today, this NOC retained an 

interest in two blocks, BCO III/BCS 11/BLT I,170 in 

Chad where it discovered oil in 2011. In 2003, CNPC 

bought out the shares of a Swiss company for Block 

H, in whose Bongor Basin the company subsequently 

made several commercial discoveries starting in 2006. 

In 2007, CNPC and the Chadian Ministry of Petroleum signed an agreement for the establishment of a 

60-40 joint venture, 20,000-bpd refinery in Ndjamena, 

which started production in 2011.171 CNPC completed 

in 2011 the construction of a 311-km pipeline from its 

fields to the new refinery.172 Based significantly on the 

growing weight of PRC investment in Chad, Ndjamena re-established diplomatic relations with Beijing in 

October 2009.173

Comoros.

The Comoros government awarded its first oil exploration license in March 2012 to the privately held 

Kenyan company Bahari Resources for an offshore 

region on the western boundary of the Comoros. The 

acreage is adjacent to offshore Area 1 and Area 4 of 

Mozambique’s Rovuma Delta, where the recent giant 

hydrocarbon discoveries were made by the U.S. firm 

Anadarko and Italian oil giant ENI. Under the agreement, Bahari will undertake a phased seismic and 

drilling program within the licensed area and will 

carry out for the government a regional study of the 

Comoros “entire territory.” The report will be used 

for the demarcation of blocks for a future licensing 

round.174 Bahari will also fund a government program 

to develop its internal expertise in upstream petroleum, including management and legislation. The 
130

government hopes to send to Parliament by October 

2013 a draft petroleum law that will govern all aspects 

of petroleum exploration and production.175

Unfortunately, the March 2012 license award has 

become mired in controversy as Luxemburg-based 

Boulle Mining claims that it had signed a prior, exclusive exploration and production agreement with 

the Comoros government in November 2011. Boulle’s 

subsidiary, Mozambique Channel Discovery, filed for 

arbitration at the International Chamber of Commerce 

in Paris in November 2012, contesting the license issued to Bahari.176 For its part, the Comoros government communicated to Boulle in May 2012 that its 

earlier agreement was invalid because it was signed 

by the Finance Minister in an acting capacity and did 

not receive approval by the Council of Ministers. Instead, the government asserts, only the Vice President 

and the Ministry for Energy, the Environment, and 

Industry are “the only mandated authorities in this 

matter.”177

As a sign of how feverish interest in Comoros territorial waters has become, former Directors of Cove 

Energy, which sold out its 10 percent stake in Rovuma 

Area 1 in Mozambique for $1.9 billion to Thailand’s 

PTTEP, formed a new company, Discover Exploration, 

specifically to raise capital and attempt to win an exploration license from the Comoros in March 2013.178

That same month, Discover announced that the Comoros had signed a PSC with Discover and Bahari for 

a block offshore Comoros adjacent to the block Cove 

Energy sold in Mozambique.179

The U.S. firm GX Technologies completed in May 

2011 seismic studies of part of Comoros’ territorial 

waters, from the Tanzanian maritime border at Mtwara, southward to Tanzania’s Pemba, then to the island of Mayotte, which is part of France but claimed 
131

by the Comoros.180 In July 2012, the Comoros government signed an agreement with the Norwegian firm 

TGS Nopec for (seismic) exploration of other zones 

in the country’s territorial waters.181 The UK’s Avana 

Petroleum has carried out “an initial analysis of the 

hydrocarbons prospectively of the waters around the 

Comoros Islands,”182 but this may mean that it purchased seismic data from GT Exploration or another 

contractor. 

Congo (Brazzaville).

Congo is the fourth-largest oil producer in Africa that is not part of OPEC, after Egypt, the Sudans 

(counted jointly), and Equatorial Guinea. Congo had 

proven oil reserves of 1.94 billion barrels at the end 

of 2011.183 Congo produced 302,000 bpd in 2010, surpassing the previous peak of 292,000 bpd in 2000. In 

2010, 49 percent of Congo’s oil exports went to the 

United States, and 31 percent went to China.184 Congo 

has produced oil since the 1960s, with production increasing until about 2000, and declining afterwards 

until 2008, when new offshore fields reversed this 

trend. Congo’s first deepwater field, Moho-Bilondo, 

has been the most important. This field, operated by 

France’s Total, came online in 2008 and reached production of 90,000 bpd in 2010. Total’s share in the field 

is 53.5 percent, along with partners Chevron with 31.5 

percent, and Congo NOC SNPC with 15 percent. Total 

operates nine of the 22 active fields in Congo and has 

a non-operator share in two others.185 Total has decided to move forward with the $10 billion deepwater 

Mogo-Bilondo “Phase 1 bis” and Moho North joint 

development project, with production beginning, respectively in 2015 and 2016,186 and peak production of 
132

140,000 bpd in 2017.187 Two appraisal wells drilled by 

Total in 2010 also confirm the growth potential of the 

southern part of the field.188 Italy’s ENI produced over 

one-quarter of Congo’s crude oil in 2010, with production hitting 98,000 bpd.189

The U.S. firm Murphy Oil is the operator of two offshore blocks, Mer Profonde Nord (100 percent share) 

and Mer Profonde Sud (50 percent share), where it discovered oil in 2005 and started production in 2010.190

ExxonMobil tried to sell off its 30 percent, non-operator share in the deepwater Mer Tres Profonde Sud 

Block in 2010 that is operated by Total (40 percent) in 

partnership with ENI (30 percent).191 Anglo-French 

company Perenco operates four offshore fields with 

relatively small production.192 France’s Maurel et Prom 

operates and is exploring the Noumbi onshore field, 

which is adjacent to the producing M’Boundi onshore 

fields193 and shares the same sedimentary basin as Gabon.194 The UK’s SOCO International operates and is 

exploring the offshore Marine XI field in the North 

Congo Basin.195 (The presence of oil in Congo, as in 

Angola’s Cabinda enclave, is explained geologically 

by sediments carried by the Congo River.196) Foreign 

NOCs and IOCs with non-operator roles in Congo are 

China’s CNOOC, PetroVietnam,197 the Netherlands’ 

Vitol, Sweden’s PA Resources and Svenska Petroleum Exploration, and the UK’s Afran and AngloIrish Tullow Oil.198 CNOOC hired a ship to drill two 

wells with an option for a third in its offshore block in 

2013 1H.199

Oil Sands. 

In 2008, the Congo government awarded ENI two 

exploration permits to launch a pilot oil sands project 

located in Tchiktanga and Tchikatanga-Makola200 in 
133

southern Congo. Congo has estimated recoverable reserves from the project of between 500 million and 2.5 

billion barrels. 201 The exploration phase includes collecting data from sounding holes in order to evaluate 

the quality, thickness, and distribution of the tar sand. 

The small-scale pilot project that might follow would 

“exclude open-cast mining and tailing ponds, which 

are considered to have a high-risk impact and both of 

which are used in oil sand operations in Canada.”202

Shared Development Areas.

As noted previously in the section on Angola, 

Congo (Brazzaville) and Angola signed an agreement 

in March 2012 to jointly exploit the Lianzi cross-border oil field on their mutual border and share profits 

equally. Following this, Chevron announced in July 

2012 that it would proceed with five partners, including Angola and Congo NOCs, in the development of 

the Lianzi Field, via a tieback to its existing BBLT platform in Angola’s Block 14. 

Natural Gas.

Congo also has large reserves of associated gas—

the fifth largest in sub-Saharan Africa at 3.2 tcf. The 

country produced 298 bcf of natural gas in 2010, although only 14 percent (43 bcf) was marketed. Sixtyfive percent was re-injected, and the remaining 21 

percent was flared or vented.203 ENI signed an agreement in 2008 to eliminate all gas flaring at its Congo 

operations by 2012 by constructing two electric power 

stations fueled by associated natural gas from the 

M’boundi Field and by re-injecting the remaining gas 

into the deposit.204
134

Cote d’Ivoire.

In 2010, crude oil production decreased by an 

estimated 24 percent to 16.4 million barrels.205 Cote 

d’Ivoire has proven reserves of 100 million barrels of 

oil and 1.1 tcf of natural gas, but a dramatic increase 

in exploration and drilling after oil and gas finds in 

neighboring Ghana are likely to significantly boost 

these figures in coming years. The producing Baobab 

Field, which came on stream in 2005, has an estimated 

200 million barrels of oil and the producing Espoir 

Field, which came on stream in 2002, is estimated to 

contain a further 120 million barrels of oil.206 Baobab 

has been operated by Canadian Natural Resources 

(57.6 percent), along with Sweden’s Svenska Petroleum Exploration (27.4 percent) and Petroci (15 percent).207 The Foxtrot offshore gas field was discovered 

along with the Panthere gas and condensate field in 

1993 and the Lion oilfield in 1994, both of which came 

on stream in 1995. UK firm Afren (47.96 percent share) 

operates the Lion and Panthere Fields, whose production averaged almost 5,000 bpd of oil equivalents, 

with SK Energy (12.96 percent share) and two Ivorian 

partners. In its 65 percent share of Block CI-01, which 

is on the maritime border with Ghana and west of the 

Jubilee Field, Afren is carrying out 3D seismic work. 

Block CI-01 has been the sight of 10 successful discoveries of oil and gas in the Ibex and Kudu Fields, while 

only gas was discovered in the Eland Field.208

Italy’s Edison International made a discovery in 

Block CI-24 in September 2010 in the Baobab Field, 

which it shares with Sweden’s Svenska Petroleum Exploration (20 percent) and Petroci.209 Russia’s Lukoil 

made an oil discovery in offshore Block CI-401 in De-
135

cember 2011. It operates the block with a 56.66 percent 

interest, along with U.S. firm PanAtlantic (formerly 

Vanco) with a 28.34 percent share, and Petroci with 15 

percent.210 Lukoil, which also has a share in Block CI101,211 signed a PSA with the Ivoirian government in 

October 2012 for a 60 percent share of offshore Block 

CI-524, along with PanAtlantic (30 percent) and Petroci (10 percent).212 In February 2013, Lukoil announced 

that it planned to spend $400 million in 2013 to drill 

more wells near the site of its discovery in Block CI401, and carry out further exploration on 3-4 offshore 

blocks.213 Operator Anglo-Irish Tullow Oil discovered 

oil in exploration Block CI-103 (share 45 percent), 

which is east of the Espoir Field, along with partners 

Anadarko (40 percent) and Cote d’Ivoire NOC Petroci 

(15 percent share). In June 2012, Tullow’s Exploration 

Director Angus McCoss said: “The discovery of light 

oil in our first well in CI-103 extends the proven play 

for oil westwards from our successes in Ghana. . . . 

We look forward to further drilling in CI-103 during 

2013.”214 In September 2012, Australia’s Rialto Energy 

estimated that the initial gas production from its Block 

CI-202 Gazelle Field 80 km west of Ghana’s huge Jubilee Field would produce 40 million cf of gas daily. 

Operator Rialto has an 85 percent interest in the block, 

shared with Petroci (15 percent).215

France’s major, Total, discovered oil at its Ivoire 

1X deepwater exploration well in May 2013. The well 

“confirms the extension into Block CI-100 of the already proved active petroleum system in the prolific 

Tano Basin, home to several fields, including Jubilee 

in Ghana.”216 In 2010, Total acquired a 60 percent interest in Block CI-100, with Yam’s Petroleum217 owning 25 percent and Petroci 15 percent.218 One observer 

believes that Cote d’Ivoire may be more willing to 
136

settle a maritime boundary dispute with Ghana now 

that there is a find that is definitively on its territory 

and pressure from major oil companies.219 In February 

2013, Total secured three new “ultra-deep” offshore 

licenses, as operator (54 percent share) of CI-514 with 

Canadian Natural Resources (36 percent) and Petroci (10 percent), and as operator (45 percent share) 

of CI-515 and CI-516 with Anadarko (45 percent) and 

Petroci (10 percent). Total’s Senior Vice President for 

Exploration, Marc Blaizot explained the acquisitions 

as follows: 

The so-called Abrupt Margin theme that will be exploring in this acreage is . . . the same theme in exploration licenses in French Guyana, where a promising 

discovery has already been made, and in Mauritania.220

Australia’s African Petroleum operates 90 percent 

shares of Blocks CI-509 and CI-513 with Petroci (10 

percent) and hopes to drill one well on each block in 

late 2013 or early 2014,221 while the Netherland’s Vitol 

is operator (36 percent share) with Genel Energy (24 

percent) and Petroci (40 percent) in offshore Block CI508, where it plans a first exploratory well in 2014.222

The Democratic Republic of the Congo.

Exploration for oil and gas in the DRC from the 

1960s to 1983 led to the discovery and development of 

five oil fields and one still-undeveloped gas field. Of 

these, the Mbale offshore field contains 48 percent of 

the Coastal Basin’s recoverable reserves.223 Nevertheless, the future of oil exploration for the DRC lies principally in the east, in the Albertine Graben, where oil 

has already been discovered in significant quantities 
137

across the border in Uganda. The five blocks on the DRC 

side of Lake Albert are said to hold 800 million barrels 

of oil.224

Unfortunately, controversy has dogged onshore 

oil Blocks 1 and 2 in eastern DRC. Anglo-Irish Tullow 

Oil and the UK’s Heritage Oil225 were awarded the 

blocks in 2006 but the DRC government cancelled the 

licenses under controversial circumstances, claiming that the contract did not follow international 

standards. In 2008, South Africa’s Divine Inspiration Group signed a competing contract for Block 1. 

Tullow initially launched legal proceedings, but then 

abandoned them as unenforceable. In 2010, two other companies from the UK, Caprikat and Foxwhelp, 

obtained licenses for Blocks 1 and 2 after the government again cancelled the existing licenses.226 France’s 

Total purchased a now 66.67 percent operator share 

of Block III in eastern DRC, in the Albertine Graben, 

with CoHydro owning 15 percent, and South Africa’s 

SacOil 12.47 percent and Divine Inspiration Group 

5.86 percent.227 Sweden’s PetroAfrican Resources presented in 2011 an extensive geological report of Block 

IV in the eastern Congolese Rift Zone, concluding that 

“the Block is a promising area for hydrocarbons.”228

The UK’s SOCO’s has encountered different challenges in exploiting its 85 percent operator share of Block 

V in onshore eastern DRC, adjacent to the border with 

Uganda, with DRC NOC CoHydro holding 15 percent. 

The block is 7500 km2, encompassing a section of the 

mountain gorilla-rich Virunga National park, including part of Lake Albert,229 and its exploration has come 

under criticism by some international environmental 

groups, including the World Wide Fund for Nature.230

The European Commission plans to do an environmental study of the area covered by Blocks III (Total-
138

operated), IV (open), and V (SOCO-operated), including evaluating the political risk of the development of 

oil resources in an area that has seen numerous armed 

conflicts since the 1990s.231 Perhaps in part due to such 

difficulties, the DRC government announced in February 2013 that it planned to adopt as early as April 

2013 a new law regulating its oil and gas sector, which 

would include a provision requiring all potential investors to go through a tender process.232

Further south, Canada’s Alberta Oilsands concluded a farm-in deal with operator Pan African Oil 

to jointly develop the Klembe Block (Block 5) and the 

Fatuma Block (Block 6) in the Kalemie sub-basin on 

Lake Tanganyika (DRC side), in the heart of the Western Rift Valley of the East African Rift System. These 

blocks are adjacent to acreage held by Total (in Tanzania on the eastern side of the lake).233

Further to the west, SOCO International undertook 2D seismic work at its 65 percent operated share 

in the Nganzi onshore block in the western Bas-Congo 

Region near the coast234 and was examining plans as 

of March 2013 to drill two wells in the block.235 Its 

partners were DRC NOC CoHydro (15 percent) and 

Japan’s INPEX (20 percent). The U.S. firm EnerGulf 

is the operator of the Lotshi Block in the onshore salt 

Coastal Basin, which is contiguous with the highly 

prospective Cabinda enclave of Angola to the north, 

and in trend with the M’Boundi field in the Republic of Congo in a similar geological graben. This basin 

also includes the East-Mibale and other fields operated by the Anglo-French Perenco Oil and contiguous 

to the east with a bitumen mining license with known 

surface oil seeps.236 EnerGulf had planned a three-well 

drilling program in summer 2011,237 but this was de-
139

layed and its DRC partner, CoHydro, now expects that 

at least one well will be drilled in 2013.238 A 2011 assessment by an outside consultant reached an estimate 

of 313 million barrel mean estimate of gross prospective oil resources in the EnerGulf’s seven prospects in 

the Lotshi Block.239 The Anglo-French company Perenco, currently the DRC’s sole oil producer at 28,000 

bpd, operates 12 onshore and offshore fields south of 

Angola’s Cabinda and north of Angola’s Soyo, storing crude on board the Kalamu, a floating terminal. It 

has a 50 percent share, with partners INPEX (Teikoku) 

(32.28 percent) and Chevron (17.72 percent).240

Negotiations with Angola. 

In September 2012, the DRC Minister of Hydrocarbons predicted that in 6 months, the two countries 

would come to an agreement over the so-called Common Interest Zone created in 2004, but that shared production of any resources was still some time off. The 

DRC could receive royalties from production already 

underway in the Zone.241 In 2010, U.S. firm Chevron 

signed an agreement with the DRC government, allowing it to ship gas from Angola’s Cabinda enclave, 

cutting across the DRC’s narrow strip of Atlantic coast 

to its new Soyo LNG plant. The Soyo facility could 

also be used to process DRC gas, and Chevron has 

expressed an interest in looking at potential gas deposits in Congo,242 and in processing DRC gas that is 

currently flared.243

Djibouti.

In 2011, the UK’s Oyster Oil and Gas won a 100 

percent operator interest in three onshore blocks in 

the Guban Basin (Blocks 1 and 4), the Red Sea Basin 
140

(Block 2), and one offshore in the Red Sea (Block 3).244

The Guban Basin extends from Djibouti into Somalia’s 

northern province of Somaliland where there have 

been oil seeps and recovery of oil from wells drilled 

in previous decades. The Red Sea Basin has had several discoveries in its northern area in Sudan, Egypt 

and Saudi Arabia, and there are also analogues with 

the large Jurassic oil fields located nearby in Yemen.245

Oyster is confident that oil-bearing basins were formed 

with the break-up of Gondwanaland in Guban Basin 

and the Red Sea. Block 1 is mainly onshore, but also 

extends into the Gulf of Aden Margin.246 After a July 

2012 with Djibouti’s Energy Minister, Oyster Chief Executive Officer Ravindra Shaji said that: 

Four months after the commencement of work on different sites in the north and south of Djibouti territory, 

we have come to report . . . the preliminary finding of 

this first phase of oil and gas exploration, which we 

can say are rather encouraging at several sites.247

Egypt.

Egypt is the largest oil producer in Africa that is not 

an OPEC member, and the second largest natural gas 

producer on the continent after Algeria. Egypt is also 

the only African oil and gas producer besides Tunisia 

that consumes domestically all or a large fraction of 

its production. As of January 2012, Egypt’s proven oil 

reserves were 4.4 billion barrels. In 2011, Egypt’s total 

oil production averaged 710,000,248 of which approximately 560,000 was crude oil including lease condensates and the remainder natural gas liquids. Egypt’s 

production peaked at over 900,000 bpd in the 1990s. 

However ongoing successful exploration and enhanced oil recovery techniques in existing fields have 
141

eased the decline at aging fields, and boosted proven 

oil reserves.249 In the second half of 2012, Egypt made 

29 oil and natural gas discoveries; in the first quarter 

of 2013, there were 13 oil discoveries and four gas discoveries in the Western Desert, the Gulf of Suez, the 

Mediterranean, and Upper Egypt that added 12 million barrels of crude oil and condensates and 125 bcf 

of gas to Egypt’s reserves.250

One of Egypt’s challenges has been to satisfy increased domestic demand despite falling domestic 

production. Domestic oil consumption grew over 30 

percent over the last decade, from 550,000 bpd in 2000 

to 815,000 bpd in 2011, outpacing production as of 

2008. Political unrest from the “Arab spring” and its 

aftermath did not directly affect foreign oil investors 

in Egypt as the top producing regions—the offshore 

Nile Delta and the Western Desert—are far from population centers. Since 2000, oil output in the Western 

Desert has doubled, and it now accounts for around 

28-30 percent of total oil production.251 Four other major producing areas in Egypt are the Eastern Desert, 

Mediterranean Sea (onshore and offshore), the Gulf of 

Suez, and the Sinai Peninsula.252

Egypt’s natural gas sector has been expanding rapidly, with production more than tripling from 646 bcf 

in 2000 to 2.2 tcf in 2010. Egypt’s proven gas reserves 

registered at 77 tcf, a sharp increase from 2010 estimates of 58.5 tcf, and the third highest in Africa after 

Algeria and Nigeria.253 Three-fourths of Egypt’s natural gas production came from Mediterranean offshore 

blocks, where 78 percent of the country’s gas reserves 

are located.254 Dry natural gas exports began in 2003 

and had been rising rapidly with the completion of the 

Arab Gas Pipeline in 2004 and the start-up of the first 

three LNG trains at Damietta in 2005. ENI operates 
142

Damietta, and Spain’s Repsol is a partner.255 However, 

gas exports leveled off in 2006 and fell in 2010, in part 

due to low international prices and growing domestic 

demand, which led the government to enact a twoyear moratorium on new gas export deals.256 Electricity shortages during summer 2010 also led to domestic 

pressure to reduce natural gas exports, which fell to 

30 percent of contracted quantities in 2011, in part also 

due to a series of attacks on a pipeline supplying Israel 

and Jordan.257

The Egyptian government encourages IOCs to participate in the oil and gas sector, and currently more 

than 50 are operating in Egypt.258 In April 2013, Egypt 

announced the award of eight new oil and gas blocks 

to six companies (out of 15 blocks offered): BP, Dana 

Gas, the UK-based subsidiary of the Korea National 

Oil Company, Italy’s Edison, Ireland’s Petroceltic International, Australia’s Pura Vida, and Canada’s Sea 

Dragon Energy.259 One possible policy change apparently being floated as a trial balloon by the Egyptian 

government is to change its licensing policy so that 

future oil and gas contracts have terms more similar 

to those offered by Algeria and Libya, with a higher 

take of production for the government—a strategy 

that risks backfiring as foreign investors are already 

alarmed about security in North Africa and a rising 

cost of doing business.260

The U.S. firm Apache is the largest producer of 

liquid hydrocarbons and natural gas in the Western 

Desert and the third largest in Egypt. In 2011, the firm 

drilled 221 wells, and produced daily 217,000 bpd of 

crude oil and 865 mcf of natural gas (including joint 

venture partner-shares). Apache planned to drill 

270 wells in 2013, of which 60 would be exploration 

wells.261 Eighty-two percent of its acreage is undevel-
143

oped, which includes seven new development leases 

in the Faghur Basin,262 providing significant future 

E&P opportunities.263 In May 2013, Apache announced 

finds in new discoveries in three concessions, each in 

different basins: North Ras Qattara, Siwa, and North 

Tarek.264 NOC Oil India has a 25 percent non-operator interest in offshore Blocks 3 (South Quseir in the 

Red Sea) and 4 (South Sinai, at junction Red Sea/Gulf 

of Suez).265

The UK’s BP and its partners produce more than 

35 percent of Egypt’s natural gas and almost 40 percent of its oil production.266 BP and Germany’s RWE 

announced a joint investment of $9 billion for the development of the North Alexandria and West Mediterranean deepwater gas fields, owned 60 percent by 

BP (operator) and 40 percent by RWE.267 Production at 

the project was to have started in 2014, but has been 

delayed by public protests. The project has the potential to unlock around 50 tcf of gas resources in the Nile 

Delta Basin, which would double Egypt’s current gas 

reserves.268 Another BP partner, Italy’s ENI, claims 

to be the “largest foreign energy player in the country,” and had oil and natural gas equity production in 

2011 of 240,000 BOE/D. In February 2013, ENI made 

a new oil discovery in the Meleiha Concession in the 

Western Desert.269 Other major foreign partners of BP 

in Egypt are Malaysia’s Petronas, which shares equal 

38 percent and 35.5 percent shares in two 3.6 million 

tons per annum (mpta) LNG trains and 30 and 50 percent shares in Nile Delta offshore fields; Italy’s Edison, 

which has a 20 percent share in a Nile Delta gas field; 

and Dana Petroleum, which has a 50 percent share 

in a Nile Delta offshore field.270 In 2012, Shell farmed 

in as operator of the Alam El Shawish West Gas Development Project (40 percent) in the Western Desert 
144

with partners Vegas (35 percent) and GSF Suez (25 

percent), where 200 mcf/d in gas production is anticipated.271 The United Arab Emirates’ Dana Gas started 

gas production at two new wells in the Nile Delta in 

March 2013 and plans to start production at a third 

well there—all 2012 discoveries—in 2013 2Q, adding 

20 million cubic feet daily.272

Shale Oil.

Oil shale resources were discovered in the SafagaQuseir area of the Eastern Desert in the 1940s, where 

estimated reserve equivalents of in-place shale oil 

are 4.5 million barrels. In the Abu Tartour area of the 

Western Desert are estimated to have about 1.2 million barrels of in-place shale oil, while oil shale in the 

Red Sea area would be extracted by underground 

mining.273

Equatorial Guinea.

Equatorial Guinea produced an average of 252-

282,000 barrels of crude per day in 2011 and 243 bcf of 

natural gas.274 The country has three major producing 

fields: the Zafiro oil field, which is the largest in the 

country and northwest of the island of Bioko; the Alba 

gas field, to the east of Bioko; and the Ceiba oil field in 

offshore Block G of the Rio Mini Basin.275 ExxonMobil 

has a 71.25 percent interest in Block B,276 whose Zafiro 

Field produced 15 percent less in 2011 than the prior 

year.277 The U.S. firm Hess has an 80.75 percent operator interest in the Ceiba Field with partners AngloIrish Tullow Oil278 and NOC GEPetrol,279 and reported 

a 21 percent decrease in production in 2011.280 Crude 

oil production has been declining as a result of matur-
145

ing oil fields, but the recent start-up of the Aseng oil 

and gas-condensate field and the anticipated start-up 

of the Alen gas-condensate field in late 2013 are projected to revive liquids production in the near term.281

At the end of 2011, Equatorial Guinea had proven reserves of 1.1-1.7 billion barrels,282 and 1.3 tcf of proven 

natural gas reserves—the majority of which are found 

offshore Bioko Island.283

Offshore.

The offshore areas of petroleum exploration and 

development are in the shelf around Bioko Island, 

which is part of the Niger Basin surrounded by Nigeria, Cameroon, Sao Tome and Principe, and the 

shelf off Rio Muni, an enclave between Cameroon and 

Gabon.284

Bioko. In September 2012, the UK’s Ophir announced that its sixth discovery alone in offshore 

Block R in the southeastern Niger Delta, southwest 

of Bioko Island, had added 1 tcf of recoverable gas 

(80 percent share, remainder with GE Petrol).285 The 

firm’s multi-well drilling campaign targeted sufficient 

resources to meet a two train LNG threshold of approximately 2.5 tcf.286 Southeast of Bioko Island, U.S. 

firm Noble Energy made a series of oil and gas discoveries in its Block I (38 percent operator),287 including the 120,000 bpd Aseng oil field,288 and Block O (45 

percent operator), including the Alen gas-condensate 

field which included the firm’s adjacent Yoyo license 

in Cameroon, total 127 mmbl liquids and 1.25 tcf in 

natural gas. The firm is considering options for monetizing these finds (including possibly another LNG 

train).289 Noble’s primary foreign partner in Block 

I and O are Switzerland’s Glencore, with respective 
146

shares of 23.8 percent and 25 percent.290 Glencore also 

has a 50 percent working share in Block V, southwest 

of Bioko Island on the maritime frontier with Sao 

Tome and Principe, partnering with Bermuda-based 

AFEX Global, which believes the block contains a 

south-westerly extension of the Cameroon Transpressional Zone that has produced oil and gas discoveries 

to the northeast.291 In January 2012, the government 

issued a press release in which it expressed the desire to see partners in Blocks I, O, and R work together 

to plan for LNG Train 2,292 doubling the 3.7 million 

metric tons per year (mmt/y) Punta Europa LNG 

Train 1, which started operations on Bioko Island in 

2007.293 In June 2012, the government announced the 

signature of a production sharing contract for Block 

A-12 offshore Bioko with the U.S. firm Marathon.294

Marathon has a 63 percent share (65 percent with government carry interest in the Alba Field, a 52 percent 

interest in the Alba liquid petroleum gas (LPG) plant, 

a 45 percent interest in the Atlantic Methanol Production Company (AMPCO), and a 60 percent interest in 

an LNG facility on Bioko Island.295 Spain’s Repsol is 

the operator in exploratory Block C-1 next to Bioko 

Island.296

Rio Muni. In the Rio Muni Basin, the UK’s White 

Rose Energy (46.31 percent operator) had planned to 

start a drilling campaign in 2012 4Q in Block H;297 U.S. 

firm PanAtlantic (80 percent operator) has seismic 

data and is preparing for drilling in Block K—Corisco 

Deep;298 China’s CNPC (70 percent operator) has been 

exploring in offshore Block M through its Santa Isabel Petroleum subsidiary.299 China’s CNOOC also has 

rights to Block S.300 The government also approached 

China’s Sinopec about constructing a 20,000 bpd refinery.301) In December 2012, the government granted 
147

Hong Kong-registered Xuan Energy a license as operator of newly created Block Y, offshore Rio Muni, 

with a 15 percent participating interest for Brenham 

Oil & Gas, a subsidiary of American International 

Industries.302 Of the seven other production-sharing 

contracts announced at the same time, two others 

were given to U.S. firms: Block W, offshore Rio Muni, 

granted to U.S. firms Murphy Oil (operator) and Pan 

Atlantic Oil and Gas, with NOC GEPetrol as partner; 

and Block EG-02 (offshore Bioko Island), to Pan Atlantic Oil and Gas, Novamark International, Atlas 

Petroleum, and GEPetrol.303 Murphy Oil was also in 

negotiations with the government about acquiring 

interests in offshore Blocks J-14, J-15, K-14 and K-15, 

along with partners Vanco (US), Dana Petroleum 

(Korea), and NOC GEPetrol.304

Onshore. 

In November 2011, Vice Minister of Mines, 

Industry and Energy, Gabriel Lima, indicated that the 

government: 

was also inviting companies to participate onshore. 

We have only one company, Total, which has drilled 

two wells onshore . . . if you look at the basins onshore 

in Cameroon and Gabon, that is where they have the 

majority of the oil.305

Maritime Boundary Disputes.

Since mid-1999, there have been strained regional 

relations over maritime boundaries, particularly the 

Zafiro Field Block B, which Nigeria has claimed is 

part of the same structure as its Ekanga oil field, just 

3.5 km north of Block B. After Equatorial Guinea’s 
148

President Obiang accepted an equidistant median line 

defining territorial boundaries as stipulated under 

UNCLOS, Cameroon, Sao Tome and Principe, and Nigeria welcomed this decision. Equatorial Guinea and 

Gabon have disputed the ownership of three islands 

in the Gulf of Guinea since the 1970s, but agreed in 

2004 to allow joint oil exploration in the disputed territories until a final resolution is worked out under 

UN mediation.306

Eritrea.

Eritrea has been underexplored for oil and gas in 

part due to political instability, including its war of 

independence from Ethiopia (1961-91), war with Ethiopia (1998-2000), and an autocratic regime that, more 

recently, was subjected to UN sanctions in December 

2011 requiring that foreign mining (but not explicitly 

energy) companies ensure funds from the sector are 

not used to destabilize the region.307 This being said, 

there are strong signs that Eritrea has great potential 

over the long term as an oil and gas producer.308

The Eritrean government signed oil exploration 

agreements in 2008 for the two most northerly offshore 

blocks on the maritime border with Sudan—Bahri 

and Defnin—with Defba Oil Share Company, which 

was reportedly a joint venture between a Chinese 

company and the Energy Alliance Company, which 

reportedly had Saudi and Bahrain capital.309 Canada’s 

Centric Gas and Oil Company signed an exploration 

agreement with Eritrea in 2010 for a mixed onshoreoffshore block in the Dahlak Block in the north-central 

Dismin region in northeastern Eritrea. Centric’s CEO 

Alec Robinson noted that, historically: 
149

Eight . . . offshore wells had good oil or gas shows, 

and the widespread occurrence of seeps is further 

evidence of a working petroleum system. . . . In fact, 

one well, C1, drilled in 1969 by Mobil, suffered a massive gas blowout, and continued flowing for 55 days 

before stopping naturally. From the limited . . . data 

available, a number of prospects and leads have been 

identified in both the pre- and sub-salt formations of 

the Eritrean Red Sea.310

Eritrea has 12 oil blocks.311 There has been little public information about the Defba or Centric deals since 

they were announced, although one March 2013 news 

item claims that Eritrean President Isaias Afwerki told 

the Middle East newspaper “Asharq Al-Awsat” that 

Eritrea has “a large [oil] reserve,” but we should not 

talk about this without verifying all the angles.”312

The southern part of the Red Sea, where Eritrea is 

located, is a boundary area between the African and 

Arabia Plates. Uganda’s Basin, which is located in the 

same East African Basin, has had major oil discoveries in a sedimentary basin only one-quarter of the areal distribution of Eritrea’s. U.S. firm Anadarko did 

promising seismic work in the Zula Block in central 

offshore Eritrea, but swapped the property with Italy’s ENI. Just beyond Eritrea’s maritime border with 

Sudan, IPC’s Suakin-2, drilled in the mid-1990s, found 

gas. Anadarko also drilled three unsuccessful wells in 

the Edd Block, and withdrew with U.S. partner Burlington Resources from the country in 1999.313 The last 

evaluation well drilled in Eritrea, Chita-1,314 was by 

Anglo-French Perenco in 2005-06 and ended in a gas 

show, according to analysis by a Japanese geologist.315
150

Ethiopia.

Ethiopia is not currently producing oil and gas.316

The country does, however, have five sedimentary basins in Ethiopia with prospects for hydrocarbons: the 

Ogaden, Gambella (these first two are the most promising), Abbay, Omo Valley, and Mekele. 

Ogaden. 

The Ogaden, in the southeast bordering Somalia, 

has historically been destabilized as predominantly 

ethnic Somali rebels with the Ogaden National Liberation Front (ONLF) has stated that it would not allow 

the resources of the region to be exploited. In 2007, 

the ONLF destroyed an oil exploration facility outside 

Abole operated by China’s Sinopec, killing 65 Ethiopians and nine Chinese. Concerned by the security situation, Sweden’s Lundin Petroleum sold its Ogaden 

assets to Canada’s African Oil Corporation in 2009,317

and Malaysia’s Petronas sold out its shares to China’s 

Hong Kong-based PetroTrans in 2010,318 whose facilities were also threatened with attack from an Ogaden-based rebel movement.319 The Ethiopian government cancelled five production sharing agreements 

for 10 blocks with PetroTrans in July 2012, claiming 

PetroTrans had failed to raise promised financing for 

new investments.320

Despite instability in the Ogaden region, the Ethiopian government had awarded exploration rights to 

17 of 21 blocks in the Ogaden Basin as of 2011.321 African Oil has one project as 30 percent operator in the 

Ogaden Basin (Blocks 7 and 8), which it describes as 

“relatively unexplored with limited well and seismic 

data to constrain a petroleum system proved by the 
151

Calub and Hilala gas condensate fields,”322 The fields 

were discovered by Tenneco in 1973 and 1974, respectively,323 but this U.S. firm was forced to withdraw by 

the 1974 Ethiopian revolution.324 African Oil’s partners 

in Blocks 7 and 8 and Adigala are New Age (African 

Global Energy), with a 40 percent share and the UK’s 

Afren with 30 percent,325 with the Ethiopian government retaining a 10 percent back-in right into successful exploration. Afren and its partners relinquished 

Blocks 2 and 6 in order to focus future exploration on 

Blocks 7 and 8.326 SouthWest Energy, which describes 

itself as an indigenous Ethiopian energy company, 

has won three concessions (Blocks 9, 9A, and 13) to 

explore for oil and gas in the “Jijiga” (Ogaden) Basin. 

The firm has sought a $100 million private placement 

of capital327 in order to fund drilling scheduled to begin 

in 2013 2Q.328 SouthWest, using gravity, aeromagnetic, 

and seismic data, has concluded that the Ogaden has a 

newly identified rift system that is Permo-Triassic and 

Karoo age and part of: 

a prolific petroleum system in East Africa with billions 

of barrels of oil discovered in Madagascar, several trillion cubic feet . . . of gas condensate in the Ogaden 

Basin, and a large number of hydrocarbon shows all 

along the East African coastal basins.

The firm believes its three blocks have two structural traps with potential recoverable resources of 

over 500 million barrels of oil equivalent (BOE).329 It 

believes the Basin as a whole could contain between 

1.5 and 6 billion barrels of oil;330 a “competent persons 

report” evaluating SouthWest Energy’s blocks concluded that the Gambella and Jijiga Basins have best 

estimate prospective resources of 1.56 billion barrels.331

Another source estimated that Ogaden could contain 
152

5 tcf of gas deposits, which would give Ethiopia larger 

reserves than established gas producers such as Cameroon and Congo (Brazzaville).332 The Calub and Hillala fields alone are estimated to contain 3 tcf.333

Gambella.

The Gambella Basin, in the southwest bordering 

South Sudan, is believed to be an extension of the prolific Melut Basin located in southern Sudan,334 where 

hydrocarbon reserves in excess of 600 million barrels 

have been discovered. The Gambella Basin is part of 

the Central African rift system that trend across Central Africa from the Benue Trough in Nigeria, through 

Chad, into South Sudan. In 2008, Canada’s Calvalley 

obtained a 100 percent operator license for the Gimbi 

Block in the northeastern flank of the Gambella Basin.335 In January 2012, SouthWest Energy signed a 

production sharing agreement for the Gambella Block, 

which at 17,000 km2 is half the size of Belgium.336

Abbay.

In west-central Ethiopia, with South Sudan to the 

west, and the capital of Ethiopia, Addis Ababa at the 

southeast limit of the basin. 

Omo.

Anglo-Irish Tullow found indications of hydrocarbons in the first of two exploratory wells drilled 

2013 1Q on the South Omo Basin (operator, 50 percent 

share, with partners Africa Oil, 30 percent, Marathon, 

20 percent),337 which is located in southwest Ethiopia, 

east of South Sudan and north of Kenya, bordering on 
153

Lake Turkana. This was the first evidence of a working petroleum system in previously undrilled South 

Omo.338 Geologically, the Omo Basin is in the northern 

portion of the Tertiary East African Rift Trend, where 

Tullow has made two important discoveries in the Lokichar Basin of Kenya.339 Tullow’s six adjacent Kenya 

licenses, along with the Ethiopia license that it shares 

with African Oil Corp (30 percent) and the U.S. firm 

Marathon (20 percent),340 cover the Turkana Rift Basin, 

which is similar in geology to the Lake Albert Rift Basin and also a southeast extension of the geologically 

older Sudan Rift Basin trend.341 African Oil also has 

a 50 percent concession in the Rift Basin area north 

of the South Omo Block, which is an extension of the 

Tertiary-age East Africa Rift Trend in Ethiopia including South Omo and the Kenyan Blocks.342

Mekele.

Mekele is located south of Eritrea. New Age (operator, 40 percent), Africa Oil (30 percent), and Afren 

(30 percent) share a concession in Adigala close to the 

borders with Djibouti and Somalia and hope to drill 

in the El Kuran Prospect in 2013 2Q.343 Regional geophysical data suggests a sedimentary basin on-trend 

with the Jurassic Basins of Somalia.344 In 2008, Calvalley obtained 100 percent operator rights to the Metema 

Block in the center of the Mekele Basin, which is also 

part of the Central African Rift System.345

Not clearly identified as being in any of these basins is an 80 percent operator concession that Canada’s 

Epsilon Energy won in 2009 for a 82,500 km2

 trade of 

land in northwest Ethiopia346 for which it had carried 

out a high-resolution airborne gravity and magnetic 

survey as of 2011.347
154

Shale Oil. 

Ethiopia has an estimated 3.98 billion tons of oil 

shale (enough to produce about one trillion barrels of 

oil) in Tigray State, on the border with Eritrea to the 

north, and Sudan to the west, and 120 million tons of 

oil shale in the Delbi.348 As the result of a joint study 

conducted by SouthWest Energy and the Ethiopian 

government, the two negotiated a Production Sharing Agreement (PSA) to begin further exploration on 

a 13,000 km2 block in the Jimma area, which has great 

potential for the development of oil shale operations.349

Gabon.

Oil output in Gabon dropped about 40 percent 

from its peak of 370,000 bpd in 1997 to 2012, causing 

Gabon to fall to the third largest oil producer in SubSaharan Africa to the sixth largest, Nigeria, Angola, 

Sudan/South Sudan, Equatorial Guinea, and Congo 

(Brazzaville).350 In the short term, declines in production from larger fields will continue to be mitigated by 

smaller fields; nevertheless, in the long run, Gabon’s 

oil production will depend on the success of new exploration, particularly of deepwater, pre-salt fields, 

interest in which has been piqued by recent offshore 

Brazil pre-salt discoveries.351 Specifically, there has 

been a conjugation of Brazil pre-salt fields such as the 

Campos Basin with West African pre-salt formations 

in Gabon, Kwanza in lower Congo, and Cabinda in 

Angola.352

Energy Minister Etienne Ngoubou announced in 

December 2012 that Gabon’s oil production was averaging 225,000 bpd, and was expecting output to in-
155

crease slightly in 2013 and 2014. Gabon had proven oil 

reserves of 3.68 billion barrels at the end of 2011353 and 

proven gas reserves of 1 tcf.354 The country’s natural 

gas resources have not been exploited because Gabon 

lacks the infrastructure to utilize the natural gas for 

domestic industry or electricity generation. Nearly 

all the associated natural gas produced is vented and 

flared or re-injected. The country produces 73 billion 

cubic feet (bcf) of natural gas, and only 3 bcf is consumed locally, mainly in two power plants.355 There 

are no LNG terminals or projects in the country.356

The Anglo-French company Perenco has current production totaling 65,000 bpd through several 

onshore and offshore licenses. In 2011, the company 

drilled the first of six new wells in the Oba Field and 

three exploratory wells in the Arouwe offshore block 

and the Fernan Vaz Lagoon.357 Anglo-Dutch Shell produced 65,000 bpd from five fields.358 It also reached a 

deal in July 2012 to farm out a 25 percent share of offshore Blocks BC9 and BCD10 to China’s CNOOC.359

China’s Sinopec continued work on “several exploration wells” in Block G4-188.360 Sinopec’s Addax subsidiary had five production sharing agreements, two 

as onshore operator of Maghena and Panthere NZE, 

with five producing fields, two discoveries, and one 

under development.361 Addax is enmeshed in a legal 

dispute soon to be in arbitration with Gabon over 

the government’s seizure of the Obangue oilfield in 

January 2013 over a dispute of more than $1 billion 

concerning customs duties and compliance with other 

laws.362

France’s Total was operator of 26 fields and nonoperator of 1 field, cumulatively producing 58,000 

BOE in 2011. It carried out a redevelopment project 

on the Anguille Field in which 21 development wells 
156

are to be drilled. Total was the 63.75 percent operator of the deep-offshore Diaba license and is currently 

analyzing 3D data on the field. In 2010, Total farmed 

into the onshore Mutamba-Itoru exploration license 

(50 percent) with the U.S. firm VAALCO energy and 

with Perenco for DE7 (30 percent) and Nziembou (20 

percent), but relinquished the DE7 after negative exploratory drilling. Total is analyzing the other two 

fields and is carrying out seismic work on the Nziembou license area; Total expects to drill an exploration 

well on Mutamba-Itoru in 2012.363 Total also reached a 

farm out agreement with U.S. firm Marathon, which 

purchased a 21.25 percent working interest in the offshore Diaba license G4-223.364 VAALCO had a 28.1 

percent interests in exploration acreage in the Etame 

Marine Block and development areas surround the 

Etame, Avouma, and South Tchibala oilfields.365 Vaalco successfully completed a new development well in 

the Avouma Field in April 2013, with a natural flow 

rate of 3,000 bpd, and will use the same rig to drill an 

exploratory well in Prospect Mu north of the Etame 

Field.366

Other foreign oil companies active in Gabon include NOC Oil India Ltd., which has a 45 percent operator interest in onshore interior basin block Shakti 

(FT-2000) with Singapore Oil (45 percent) and Singapore’s Marvis (10 percent).367 Oil India, which began 

drilling in Shakti in November 2012, continued talks 

in February 2013 to acquire France’s Maurel et Prom 

assets in Gabon, which include 85-100 percent interests in five production permits and four exploration 

permits.368 Oil India has earmarked about 70 billion 

rupees ($1.28 billion) for overseas acquisitions to help 

the nation secure its energy supplies, but has been stymied by lengthy processes for the necessary govern-
157

ment approvals.369 In 2011, Brazil’s Petrobras entered 

the country through an agreement to buy a 50 percent 

stake from the UK’s Ophir Energy in the Ntsina Marin 

and Mbeli Marin Blocks, in the Coastal Basin, offshore 

northern Gabon.370

In November 2012, U.S. firm VAALCO made an 

oil discovery while drilling in the onshore Mutambo 

Iroru Concession. VAALCO has a 50 percent operator interest, while partner Total holds the remaining 

50 percent, with the concession subject to an 18 percent Gabon government back-in interest in the event 

of development.371 In January 2013, U.S. firm Harvest 

Natural Resources struck oil at the pre-salt Gamba 

and Dentale formations offshore in the Dussafu Marin 

Block, 372 where it has a 66.67 percent operator interest.373 This most recent discovery, along with three 

earlier ones in the block at Ruche, Walt Whitman, and 

Moubenga, brings the combined mean estimate for 

contingent resources in the block to 45 million barrels.374 The U.S. firm Cobalt International is pushing its 

own pre-salt program, partnering with Total, which 

drilled Gabon’s first one deepwater pre-salt well in 

the Diaba Block in early 2013,375 (Cobalt also plans for 

four pre-salt wells off Angola.)376

As part of a bid to attract more foreign investment 

and spur further increases in production, the Minister also announced new, investor-friendly regulations 

and a new deep offshore round of licensing in June 

2013377 involving new offshore 42 blocks.378 In January 

2013, Minister Ngoubou announced the awarding of 

an 80 percent interest in the offshore Nkembe Block 

to Australia’s Pura Vida.379 In March 2013, Pura Vida 

announced an oil discovery at the Loba M 1 well in 

Nkembe.380
158

Gambia.

In 2010, Australia’s African Petroleum entered into 

a farm-in agreement to acquire a 60 percent operator 

interest in two Gambian deepwater offshore exploration licenses, Block A1 and A4. The remaining 40 percent equity is held by the UK/Cyprus firm Buried Hill 

Energy. There are potential mean unrisked recoverable prospective undiscovered resources of approximately 500 million barrels. African Petroleum plans to 

drill the first well in the Gambia in 2013 2Q.381 There 

are no known oil or gas reserves in the Gambia, but the 

country has good prospectivity for hydrocarbons, as 

the area marks the northern extent of the CasamanceBissau sub-basin, which forms part of the MauritaniaSenegal-Gambia-Guinea Bissau Coast Basin,382 also 

known in the industry as the “MSGBC” Basin, which 

itself is part of the North-West Africa Atlantic Margin. In this regard, Norway’s Bergen Oilfield Services 

won a contract in 2011 with the governments of Senegal, the Gambia, Guinea-Bissau, and Guinea to carry 

out a 15,000-km, 2D seismic survey from Senegal to 

Guinea.383 Oil discoveries in Ghana and later in Cote 

d’Ivoire and Sierra Leone have encouraged increased, 

early-stage exploration from Ghana to Guinea-Bissau, 

and the Gambia appears to have direct analogies to 

many of the regional exploration successes in West 

Africa.384

In January 2012, the U.S. firm CAMAC energy 

won two offshore blocks in 600-1,000 meters of water, A2 and A5, which are east of African Petroleum’s 

Blocks A1 and A4. In 1979, Chevron drilled the Jammah-1 well on the basis of sparse 2D data and had gas 

shows.385 CAMAC Energy will be the operator with 

a 100 percent interest, with an option by the Gambia 
159

National Petroleum Company to participate up to 15 

percent following approval of a development plan.386

CAMAC believes that: 

A fresh interpretation of . . . West Africa’s petroleum 

geology . . . raise[s] the prospect of a new oil province 

in the West Africa Transform Margin, an area between 

the two tectonic plates stretching from eastern Ghana, 

Cote d’Ivoire, Liberia and Sierra Leone,

with Gambia having similar geology.387

Ghana.

Ghana produced only 8,880 bpd in 2010, but became Africa’s newest oil exporter in December of that 

year when the new Jubilee Field began shipping oil.388

Ghana’s oil production increased almost 10-fold in 

2011, reaching 84,737 bpd by year-end. The partners 

were able to increase production at Jubilee to 105,000 

bpd in December 2012 after remedial work and the 

start-up of the Jubilee Phase 1A development plan,389

including additional acid stimulation operations on 

some of the Phase 1 wells. All five Phase 1 production wells were expected to be online by 2013 1Q.390

The U.S. firm Kosmos expects Jubilee to produce an 

average of 105,000 to 115,000 bpd in 2013,391 and later 

to climb to 200,000 bpd. A Ghanaian government official said in February 2012 that Ghana hoped to boost 

crude oil output more than five-fold over the next 5 

years, to about 500,000 bpd.392

Estimates of Ghana’s oil reserves vary widely. A 

Ghana NOC official said in 2011 that Ghana’s oil reserves were at least 1.25 billion barrels.393 Jubilee alone 

is estimated to contain anywhere from 800 million to 

1.8 billion barrels of oil,394 although Kosmos estimated 

the field at 600 million BOE to 1 billion barrels.395
160

Ghana has five sedimentary basins: the inland Voltaian Basin, the offshore Accra-Keta Basin with an onshore extension, the offshore Saltpond (Central) Basin, 

the offshore Cote d’Ivoire-Tano Basin with an onshore 

extension, and the offshore Cape Three Points Basin 

(sometimes considered part of the Tano Basin.)396

The government of Ghana has published a list of 

petroleum agreements executed between Ghana National Petroleum Corporation (GNPC) and various 

companies for petroleum exploration and production 

rights between 2002 and 2008 for 12 acreages awarded 

to 10 operator companies:397

1. U.S. firm Kosmos Energy, over the Deepwater 

West Cape Three Points Block. Kosmos (30.87 percent operator) made discoveries at Mahogany (2008), 

Kosmos made discoveries at Mahogany (2008), Teak 

(2011), Akasa (2011), and had a technical success at 

Banda (2012).398 Other partners are Anadarko (30.87 

percent), Anglo-Irish Tullow (22.9 percent), GNPC (10 

percent), the EO Group (3.5 percent), and Sabre Oil 

(1.86 percent).399 The consortium is in the pre-development plan phase for this cluster of fields known as 

MTAB (Mahogany, Teak, Akas, and Banda). 

2. Tullow, over the Shallow Water Tano Fields, including the discovered North and South Tano Fields; 

and the West Tano Heavy Oil discovery. 

3. Tullow, 49.95 percent operator, over the Deepwater Tano Basin, with partners Kosmos (18 percent), 

Anadarko (18 percent), Sabre (4.05 percent), and GNPC 

(10 percent). The world-class Jubilee Field was discovered in 2007 and reached first production in 2010—a 

record time. The field straddles both the deepwater 

Tano and West Cape Three Points Blocks.400 Tullow’s 

share is 34.71 percent, Anadarko and Kosmos each 

have 23.49 percent, GNPC has 13.75 percent, Sabre Oil 
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& Gas Holdings has 2.81 percent, and and E. O. Group 

has 1.75 percent.401

The Ghanaian government approved in May 2013 

a development plan for a new cluster of fields in deepwater Tano known collectively as TEN (Tweneboa, 

discovered in 2009), Enyenra (2010), and Ntomme 

(2011).402 The capital expenditures for the TEN project are around $4.5 billion, which includes around 

23 injection and production wells and excludes floating production, storage, and offloading (FPSO) lease 

costs—a figure so large that Tullow hopes to sell a 

piece of its interests in the project to raise financing. 

First production is expected within 36 months403 with 

peak production of 80,000 bpd.404 Kosmos also made 

a discovery at the Wawa-1 exploration field in deepwater Tano in August 2012, which may lead the firm 

eventually to co-develop a fourth cluster of fields in 

Ghana, along with Jubilee, MTAB, and TEN.405

4. The Netherlands’ Vitol, over the Offshore Cape 

Three Points area, east of the Kosmos acreage. ENI 

took over as operator (47.22 percent interest), with Vitol (37.78 percent) and GNPC (15 percent, with an option for an additional 5 percent).406 ENI discovered gas 

at both Sankofe East 1-X407 (in September 2012) and 

Gye Nyame 1 exploration wells, and is interested in 

fast-tracking the development of Sankofe,408 including 

by drilling other wells to delineate the size of the discovery and confirm commercial feasibility.409

5. Vitol, over the offshore Cape Three Points South. 

In 2009, Vitol made a discovery at Sankofa-1A.410 ENI 

took over as operator (47.22 percent interest), with Vitol (37.78 percent) and GNPC (15 percent).411

6. U.S. firm Hess, over Deepwater Tano/Cape 

Three Points (south of the Tullow and Kosmos Blocks), 

is a 55 percent operator, with Norway’s Statoil holding 

35 percent interest and GNPC holding 10 percent.412
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In 2011, oil and gas condensates were found at the 

Paradise-1 exploration well,413 with later discoveries at 

Almond (oil), Beech (oil), Hickory North (gas condensate), and, in December 2012, at Pecan-1 (oil).414 Based 

on the results of these wells and Hess’ experience in 

Equatorial Guinea, where the geology is similar, the 

firm plans to submit appraisal plans to the government by June 2013.415

7. U.S. firm PanAtlantic (formerly Vanco), over the 

Cape Three Points Deepwater Block. Russia’s Lukoil 

farmed into a 56.66 percent interest, with PanAtlantic 

retaining a 28.34 percent interest, and GNPC with a 

15 percent carried interest and the option to acquire 

up to a further 5 percent in any commercial discovery. 

In 2010, PanAtlantic made an oil and gas-condensate 

discovery at the Dzata-1 exploratory well.416 Lukoil 

subsequently drilled two wells with noncommercial 

hydrocarbon reserves and plans to drill another well 

in 2013 4Q,417 with the hope of cumulatively finding 

150-200 million barrels of oil—enough to make the 

production profitable.418

8. Norway’s Aker ASA, 85 percent operator of the 

Deepwater Tano South contract Area, which is the 

western part of the area relinquished by PanAtlantic. 

Partners are GNPC (10 percent) and Chemu Power, 

a local Ghanaian Company (5 percent). South Deepwater Tano is located further offshore in the Gulf of 

Guinea and at greater water depths than Tullow’s Jubilee field.419 PanAtlantic planned one exploration and 

1-3 appraisal wells in 2012-2013.420

9. India’s Gasop Oil, over Deepwater Saltpond Basin. Gasop is owned by OMEL, which in turn is a joint 

venture between India’s ONGC and Mittal.421

10. Saltpond Offshore Producing Company Limited, over the existing Saltpond Field. This company is 
163

a joint venture between the U.S. firm Lushann International, Nigeria’s Eternit, and GNPC. Lushann-Eternit 

Energy Ltd. has a 55 percent share, while GNPC has 

45 percent. This company is Ghana’s oldest oil production company and the Saltpond Field has been 

in production intermittently for over 25 years. Daily 

production is currently about 600 bpd,422 down from 

a peak of 4,800 bpd. In 2000, GNPC had entered into 

an agreement with Lushann International for the rehabilitation of the Saltpond Oil Field.423

11. Nigeria’s Oranto Petroleum International Limited, over the Saltpond area. 

12. Italy’s ENI, over the deepwater Keta Basin, with 

a 35 percent operator interest, with the UK’s Afren 

(35 percent), Japan’s Mitsui (20 percent), and GNPC 

(10 percent). ENI took over from Afren as operator 

in 2011. The Keta Block is in the offshore part of the 

Volta River Basin in eastern Ghana, next to the maritime boundary with Togo.424 The consortium failed 

to encounter hydrocarbons in Nunya-1X exploration 

well,425 but believes the basin retains a high potential 

and plans to drill another exploratory well in 2014.426

Other Fields.

Two other exploration areas are offshore Accra and 

the onshore Voltaian (or Volta River) Basin. Australia’s Tap Oil has a 45 percent interest in offshore Accra 

acreage.427 In December 2012, the UK’s Ophir Energy 

(new operator), Rialto (12.5 percent share), and Vitol 

farmed-in to this acreage, which shows similarities to 

Jubilee, and planned to drill the Starfish-1 exploration well in 2013.428 Tap said the well had a P50 (50% 

probability) resource of 431 billion barrels and could 

be comparable in size to Jubilee.429 Canada’s Simba 

Oil has submitted an application for acreage in east-
164

central Ghana in the Voltaian Basin and hopes it could 

“represent a large gas play.”430

National Gas Processing Project.

In July 2012, China’s Sinopec won a $750 million 

contract to develop Ghana’s National Gas Processing 

Project, which involves transporting and marketing 

associated gas from the Jubilee Field. The Chinese government offered financing and agreed to accept repayment in the form of a long-term oil supply contract. 

Chinese firms are involved in several other energyrelated projects, including thermal power plants and 

the Bui hydroelectric project.431 Gas will be distributed 

from a central processing facility at Domunli; a 120-km 

onshore gas line will deliver dry gas to the Aboadze 

thermal power station, while another 75-km onshore 

line will connect to the mining center of Prestea.432

Sinopec, for example, is the contractor for a project to 

be completed by July 2013 to build a pipeline from the 

offshore Jubilee Field to deliver 150 million cf/d to the 

Aboadze plant.433

Territorial Dispute with Cote d’Ivoire: 

No Impact on Exploration and Production.

Ghana has a long-standing maritime territorial 

dispute with Cote d’Ivoire that reignited in 2010 after Ghana started commercial oil production. Cote 

d’Ivoire has been claiming ownership of billions of 

barrels of oil and cubic feet of gas reserves found in 

deep waters near the coast of Ghana and covering 

portions of the Jubilee, Field, Tweneboa, Enyenra, 

and Owo discoveries and West Tano-1X find.434 Both 

countries had previously made submissions in 2009 to 

the UN Commission on the Limits of the Continental 
165

Shelf.435 IOCs continue work in the disputed areas under the assumption that they belong to Ghana, given 

that the UN’s International Court of Justice has not issued an injunction against Ghana pending its adjudication of the dispute. 

Guinea.

Guinea does not produce oil or gas, but there is 

ongoing offshore and onshore exploration.436 The U.S. 

firm Hyperdynamics holds one of the largest offshore 

exploration acreage positions in West Africa, at 25,000 

km2, with depths from 100 meters to 4,000 meters.437 It 

has acquired 17,800 km of 2D seismic and 3,635 km of 

3D seismic data.438

The company relinquished a portion of its original, 

31,000-square-mile concession in 2009 under the then 

military government.439 According to the U.S. Foreign 

Commercial Service, Hyperdynamics relinquished 70 

percent of its original concession to the Transitional 

government. Some speculated that officials in the 

Transitional government had awarded much of this 

offshore acreage to China Sonagol, a joint venture between the Angolan NOC and Duyuan International 

Development. However, the government of Alpha 

Conde, who, in December 2010, became the first democratically elected President in Guinea’s 50-year history, said it will review agreements made by previous 

regimes.440 China Sonangol’s website does not list any 

oil and gas operations in Guinea, but does list a Conakry office.441 In January 2010, Hyperdynamics farmed 

out 23 percent of its concession to Dana Petroleum, a 

wholly owned subsidiary of the Korea National Oil 

Company; in February 2013, it completed the farm out 

of 40 percent to Anglo-Irish Tullow Oil. CEO Leonard 

said that: 
166

We look forward to working with Tullow Oil as they 

apply their successful exploration experience on the 

Atlantic Margin . . . particularly the Transform Margin 

play that is present in the Guinea acreage.442

The partners intend to drill a deepwater well before 

April 2014.443 Earlier, in February 2012, Hyperdynamics announced that its exploratory well Sabu-1 had 

encountered hydrocarbons that its CEO Ray Leonard indicated “enhances the prospectivity of our . . . 

concession.”444

In 2011, Canada’s Simba Energy signed an agreement with Luxembourg-based Summa Energy for a 60 

percent operator share in 12,000 km2

 in onshore Blocks 

1 and 2 in Guinea’s Bove Basin,445 which has three 

known reservoir systems.446 During the firm’s initial 

exploration work in February 2013, Simba identified 

numerous oil seeps in both blocks.447 It plans to drill 

the first of two test wells later in 2013.448

The government of Guinea announced that it plans 

to put 22 new offshore blocks up for auction after it 

puts its new petroleum code in place, hopefully by 

June 2013.449

Guinea-Bissau.

While there is currently no oil or gas production in 

Guinea-Bissau, there have been oil discoveries in both 

the country’s offshore blocks and its Joint Development Zone (JDZ) with Senegal. The Zone, principally 

known by its French name, Agence de Gestion et de Cooperation entre la Guinee-Bissau et le Senegal (AGC), was 

established under the terms of a 1995 agreement that 

addressed a territorial dispute between the two coun-
167

tries and divided proceeds from activity in the joint 

exploration area between Guinea-Bissau and Senegal 

in a 15:85 ratio.450

There has been intermittent exploration offshore in 

Guinea-Bissau since the 1960s, when Esso drilled six 

wells. In 1974, Guinea-Bissau gained its independence 

from Portugal. Since then, exploration has frequently 

been affected by civil unrest. Offshore exploration 

had also been hampered by a boundary dispute with 

Senegal, which was not resolved until 1993.451 In recent years, perceptions of Guinea-Bissau’s reputation 

as a target for foreign investment has been severely 

damaged by perceptions that it had devolved into a 

“narco-state” in which Latin American drug cartels 

had corrupted the weak central government and was 

using the country as a transit point for cocaine shipments from Latin American to Europe.452

Despite this, there are at least three groups of foreign oil companies engaged in exploration in GuineaBissau and the AGC. The first group is led by Svenska 

Petroleum, a Swedish company that is 100 percent 

owned by Saudi Arabian/Ethiopian businessman 

Sheikh Mohammed H. al-Amoudi.453 Svenska is the 

operator of the Sinapa (Block 2) and Esperanca (Blocks 

4A and 5A), along with Australian partner FAR (21.43 

percent) and NOC Petroguin.454 These licenses lie on 

the continental shelf around 180 km off the GuineaBissau coast and west of the Bissau River estuary. 

Immediately to the north lies the billion-barrel Dome 

Flore discovery. The blocks have wide, shallow waters 

of an extended continental shelf, where the Sinapa oil 

discovery, made in 30 meters (m) of water, is estimated to have P50 STOOIP of 240 million barrels; several 

large untested prospects in the Sardinha Prospect are 

estimated to have unrisked P50 STOOIP of 219 million 
168

barrels. Svenska plans to drill two wells in 2013.455 Qatar’s Sphere Petroleum, a now privately held company 

formerly traded on the Australian Stock Exchange, is 

the operator of offshore Blocks 1 and 5B.456

AGC: The UK’s Ophir is the lead operator (44.2 

percent) in deepwater Block AGC Profond, along with 

partners U.S. firm Noble (30 percent), L’Entreprise 

(AGC state entity; 12 percent),457 FAR (8.8 percent), 

and the U.S. firm Rocksource Energy (5 percent).458

Ophir drilled an unsuccessful well in June 2011 and 

has undertaken analysis of the wider implications for 

the prospectivity of the Casamance Sub-basin of the 

MSGBC Basin.459

Kenya.

Major oil discoveries in Uganda in 2006 and natural gas discoveries in Mozambique and Tanzania in 

2010 have created expectations that Kenya is part of 

a new regional hydrocarbon province, attracting new 

IOC exploration. Kenya has four large sedimentary 

basins: 

• Anza, in north central Kenya, with its northern

tip touching Ethiopia and running northwestsoutheast, touching Somalia.460

• Lamu, in onshore and offshore in southeast

Kenya, may contain up to 5 billion barrels of 

oil. Geology similar to areas of Madagascar, 

the island that was joined to East Africa before 

splitting apart 145 million years ago and that 

may contain up to 24 billion barrels of heavy 

oil resources.461 At least 11 wells in Lamu have 

encountered oil and/or gas shows.462

• Mandera in the northeast tip of Kenya, bordering Ethiopia to the north and Somalia to 

the east.
169

• The Tertiary Rift Basin in western Kenya, bordering Sudan and Ethiopia to the north, Uganda to the east, and Tanzania to the south.463 Includes several sub-basins, including Lochikar, 

where Anglo-Irish Tullow Oil made two oil 

discoveries in 2012.464 Kenya’s Great Rift Valley could yield 10 billion barrels of oil, Tullow 

estimates.465

Until recently, only 28 exploration wells had been 

drilled in Kenya, averaging one well every 20,000 

km2

, with the earliest being drilled in 1992. The rush is 

now on, however, and there are already at least 12 oil 

exploration companies in Kenya, including France’s 

Total, Italy’s ENI, and Norway’s Statoil.466 As of July 

2012, the government had distributed 46 designated 

blocks, including nine offshore.467 In February 2013, 

the government announced that it would adopt an 

auction-style format for up to nine new onshore and 

offshore blocks. It had previously operated more on a 

first-come-first-served basis, but is demanding higher 

licensing fees and work program requirements now 

that Kenya has become an established area for hydrocarbons. Kenya’s production sharing contracts say that 

explorers must relinquish 25 percent of the acreage in 

a licensed area every 2 years. Anglo-Irish Tullow Oil 

and Anadarko reached this point in 2012 for seven exploration blocks, which the government now plans to 

re-demarcate into up to nine new blocks.468 The government has a $25 billion plan to construct a new port 

in the northern coastal town of Lamu that could be 

used for energy and other exports from Kenya, Uganda, Ethiopia, and South Sudan.469
170

Onshore.

Tullow Oil and Africa Oil (50 percent each) found 

crude at two onshore wells in March 2012 in the 

northern Turkana region in Blocks 10 BB (Ngamia-1 

exploratory well) and 13T (Twiga South-1),470 and now 

plan up to 11 more test wells in 2013. The IMF has 

already declared these Turkana finds as “commercial” 

and projects production of oil will start in “6-7 years,” 

while Tullow has been more cautious471—perhaps in 

part to tamp down Kenyan government expectations 

and desire to accrue more benefits to itself through new 

legislation. Tullow described this area as in the South 

Lokichar Basin, one of seven sub-basins in the larger 

Kenya-Ethiopia Rift Basin. Each of the seven is similar 

in magnitude to the Lake Albert Rift Basin in Uganda. 

Tullow also has 50 percent operator interests in Blocks 

10A and 10BA, a 65 percent operator interest in Block 

12A, and an undisclosed farmed-in, working interest 

in Block 12B,472 where Australia’s Swala Energy has 

carried out an airborne gravity-magnetic survey and 

plans a 2D survey soon.473 In March 2013, Tullow found 

light, noncommercial hydrocarbons in Block 10A in 

the Anza Basin in northeast Kenya, with Canada’s Africa Oil (30 percent) and the UK’s Afren (20 percent).474

Canada’s Africa Oil also owned shares running from 

20 percent to 50 percent of Blocks 9, 10BA, 10BB, 12A, 

and 13T, and agreed in September 2012 to sell to U.S. 

firm Marathon Oil a 50 percent interest in Block 9 and 

a 15 percent interest in Block 12A.475 As with Block 

10A, the firm’s Block 9 is in the Anza Basin, along a 

northeast-southwest trend rift that runs from southern Sudan.476 These two blocks had prospective gross 

best estimates of 1.287 billion and 588 million barrels 

of oil, respectively.477 Afren has an 80 percent operator 
171

interest in Block 1 in northeast Kenya along the border with Ethiopia and Somalia,478 along with Canada’s 

Taipan Resources, which also has a 100 percent interest in Block 2B, to the south bordering with Somalia. 

The Tarbaj oil seep in southwest Block 1 suggests an 

active petroleum system, while the northern portion is 

an extension of the Ogaden Basin in Ethiopia, which is 

estimated to contain approximately 4 tcf of natural gas 

and 715 million BOE. Block 2B is estimated to have 387 

million BOE of unrisked prospective resources.479 Taipan expects to drill its first well on Block 2B in earlier 

2014.480 Canada’s Imara Energy acquired Block L2 onshore Lamu Basin in June 2012.481 Privately held Swiss 

Oil Holdings International owns the licenses to Blocks 

L4 and L13, which are both mainly onshore at Lamu 

(L4) and further southwest along the coast.482

In July 2012, U.S. firm ERHC was awarded Block 

11A in northwestern Kenya along the border with 

South Sudan, east of where Tullow made discoveries in 10BB.483 Block 11A has parts of both the Central Africa Rift System and the Tertiary East Africa 

Rift System; the firm says that the proximity and intrend relationship between the Abu Gabra Rift Basin 

of southern Sudan and the Lotikipi Sub-basin in the 

East Africa Rift System suggest high oil and gas prospectivity.484 In May 2013, ERHC announced a letter 

of intent to farm out part of the block to an unnamed 

“integrated international oil and gas company” while 

it moves forward on a full tensor gravity gradiometry 

survey of the block.485

Canada’s Simba Oil has a 100 percent share of 

Block 2A; the southwest corner of the block extends 

into the Anza Basin in central Kenya, moving northeasterly toward the southern tip of the Mandera Basin 

in northeastern Kenya bordering on Somalia.486 Simba 
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expects to strike oil reserves of over one billion barrels 

in Wajir Region.487 In May 2013, Simba farmed out a 66 

percent share and operatorship of the block to privately owned oil and gas company, APEX Exploration.488

Canada’s Vanoil has Blocks 3A and 3B due south of 

Block 2A, bordering with Somalia to the east. These 

blocks are at the confluence of the Anza, Lamu, and 

Mochesa Basins.489 The firm also later acquired shares 

in Blocks 9, 10A, 10 BA, and 10BB, the latter two containing most of Lake Turkana.490 The UK’s Bowleven 

farmed into a 50 percent interest in Block 11B, which 

borders on South Sudan and Ethiopia and is west 

of Lake Turkana.491 In 2010, CNOOC plugged the 

Bhogal-1 exploration well on Block 9 in north-central 

Kenya after inconclusive results showed hydrocarbon 

potential.492

Offshore. 

In September 2012, U.S. firm and 50 percent operator Apache found a major offshore discovery of gas in 

offshore Block L8 about 70 km east of Malindi at the 

Mbawa-1 exploration well,493 with Australia’s Origin 

Energy (20 percent), Australia’s Pancontinental (15 

percent), and Tullow Oil (15 percent).494 Pancontinental says Mbawa has “world-class potential for oil and 

gas, with volumetric pressure easily exceeding one 

billion barrels of oil” and potentially exceeding 5.2 billion barrels and 809 bcf of gas.”495 U.S. firm Anadarko 

is the 50 percent operator of Blocks L5, L7, L11A, L11B, 

and L12, with partners Total of France (40 percent) 

and PTTEP of Thailand (10 percent).496 In May 2012, 

U.S. firm CAMAC Energy was named 100 percent operator of Blocks L1B, L16, L27, and L28, with the Kenyan government having the option to participate to 
173

20 percent upon development,497 and began airborne 

gravity and magnetic surveys of Blocks L1B and L16 

in April 2013.498 Australia’s FAR has a 60 percent operator interest in Lamu Basin offshore Block L6, where 

3D data has led to an unrisked estimate assessment 

of as much as 3.96 billion barrels of oil or 10.69 tcf of 

gas, with drilling planned for mid-2013.499 FAR, which 

recently convinced the Kenya government to restore a 

large area in Block L-6 that had been previously relinquished, estimates that L-6 has prospective resources 

of 3.96 billion barrels of oil or 10. 7 bcf of natural gas.500

FAR also holds a 30 percent interest in offshore Block 

L9,501 which is operated by the UK’s Ophir Energy. 

Ophir plans to drill a well in Block L9 in 2013.502 In 

the southern, offshore portion of the Lamu Basin, the 

UK’s BG Group is the 40 percent operator of Block 

L10A (with partners Thailand’s PTTEP, 25 percent; 

the UK’s Premier, 20 percent; and Pancontinental, 15 

percent) and L10B (Premier, 25 percent; PTTEP, 15 

percent; and Pancontinental, 15 percent).503 BG Group 

will drill at least one well in L10A/L10B in the second half of 2013.504 Afren has 100 percent interest in 

L17 and L18, both of which are in the offshore part of 

the Lamu Basin adjacent to the coast, with L18 further 

east offshore, and also abutting the maritime boundary with Tanzania,505 as well as Afren’s Tanga Block in 

northern onshore and offshore Tanzania.506 The company obtained 3D seismic in 2012 for L17/L18, prior 

to exploration drilling.507

Lesotho.

There are no known hydrocarbons in Lesotho.
174

Liberia.

Offshore. 

There is currently no oil or gas production in Liberia, but considerable optimism about the possibility of a new hydrocarbon province offshore known 

as the West Africa Transform Margin.508 In 2004, 

Spain’s Repsol acquired rights to offshore Blocks 16 

and 17, the latter of which runs up to the maritime 

border with Sierra Leone.509 In 2010, U.S. major Chevron acquired three offshore blocks, LB-11, LB-12, and 

LB-14, in which it currently has a 45 percent operator 

interest, with Nigeria’s Oranto with 30 percent and 

Italy’s ENI with 25 percent.510 The U.S. firm Anadarko has 47.5 percent operator shares in Blocks LB-15, 

LB-16, and LB-17 in fields adjacent to Sierra Leone’s 

Mercury and Venus discoveries. Other partners are 

Repsol (27.5 percent) and Anglo-Irish Tullow Oil 

(25 percent).511 Anadarko drilled the unsuccessful 

Montserrado-1 well in Block LB-15 in 2011.512 Despite this disappointment, partner Tullow stressed 

that it remained optimistic about Liberia (and Sierra 

Leone) as part of an overall exploration program in 

West Africa.513

Australia’s African Petroleum made a new offshore 

oil discovery in February 2013 when it drilled the Bee 

Eater-1 well on offshore Block LB-09. The company is 

finalizing negotiations with CNPC (through its Hong 

Kong-listed arm, PetroChina) for an investment of up 

to 20 percent equity in this block.514 The Bee Eater-1 

well indicated that the oil play discovered while drilling Narina-1 in early 2012, located 9.5 km southeast, 

extends over a very large area.515 One recent estimate, which may have been revised upwards, is that 
175

LB-09 contains 500 million barrels of oil.516 African 

Petroleum also owns a 100 percent share in block 

LB-08, which is east of LB-09 and northwest of Ghana’s 

Jubilee Field.517

In March 2013, ExxonMobil purchased an 80 percent operator share offshore in Block LB-13 from Canadian Overseas Petroleum Ltd., which retained a 20 

percent share.518 One report estimated that the block 

has 2.32 billion barrels of gross prospective recoverable resources.519 Norwegian seismic player TGS has 

commenced a 3D multi-client survey covering up to 

7,800 km2

 of highly prospective acreage in the Harper 

Basin, offshore Liberia. TGS’s data processing will be 

available to clients before a 2013 4Q bid round by the 

Liberian government for new exploration blocks, including ultra-deepwater.520 Liberia currently has 17 

offshore exploration blocks and plans to creation 13 

more deepwater blocks.521

Onshore. 

Canada’s Simba energy has a 90 percent share of 

the onshore reconnaissance license NR-001 covering 

1,386 km2 of onshore coastal strip of Liberia lying with 

the Roberts and Bassa Basins. In 2010, an exploration 

team carried out an extensive oil seep survey of most 

of the license area.522

Libya.

In the mid-2000s, IOCs involvement in Libya experienced a resurgence as the United Nations (UN), 

and the United States and other nations lifted sanctions in 2003 and 2004, respectively.523 Libya was Africa’s second biggest oil producer,524 after Nigeria, and 
176

produced an estimated 1.65 million bpd prior to the 

movement in February 2011 to oust long-time dictator Muammar Qadhafi.525 This was about 2 percent of 

global production.526 This was well below the three 

million bpd in the late 1960s, but an improvement 

over the 1.4 million bpd in 2000. Libya also produced 

an estimated 140,000 bpd of non-crude liquids, including condensate and natural gas plant liquids. Output 

exceeded Libya’s OPEC target of 1.47 billion bpd. Because Libyan oil and natural gas exports were almost 

totally disrupted during several months of internal 

fighting, the International Energy Agency coordinated 

a release of 60 million barrels of oil from member-state 

emergency stocks. Libya oil production started its recovery in September 2011, production was estimated 

to have recovered to 1.4 million bpd by May 2012 and 

was seen to be on track to reach pre-conflict levels of 

1.6 million bpd by April 2013.527 In 2010, Libya had 

targeted production of 2.5 million bpd by 2015. Following the disruption in exploration and production, 

Libya has set a more modest target of 2.0 million bpd 

over the next 5 years. Libya’s domestic oil consumption is about 300,000 bpd.528

Libya is the fourth ranked African country in terms 

of crude oil production after Nigeria, Algeria, and Angola. About two-thirds of oil production—and over 80 

percent of reserves529—are from fields in the eastern 

part of the country, in the Sirte Basin, followed by 25 

percent in the southwest Murzuq Basin, and most of 

the remainder from the Pelangian Shelf Basin near 

Tripoli, with small fields in the western Ghadames 

Basin. Libya’s proven oil reserves of 47.1 billion barrels as of January 2012 were the largest in Africa,530

seventh ranked globally, and represented 3.4 percent 

of global reserves.531 The next five African countries 

in terms of reserves are Nigeria (37.2 billion), Algeria 
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(12.2 billion), Angola (9.5 billion), Sudan/South Sudan (5 billion), and Egypt (4.4 billion).532

Libya’s rank as a producer and reserve holder is 

less significant for natural gas than it is for oil. Libya 

produced 1,069 bcf of natural gas in 2010, of which 

825 bcf was marketed, 120 bcf was re-injected, and 

roughly an equal amount was vented or flared. Domestic gas consumption was 242 bcf. Most production 

is exported, almost entirely via the Greenstream pipeline under the Mediterranean to Italy. Libya’s natural 

gas reserves in January 2012 were 52.8 tcf. IOCs are 

less active in natural gas, with ENI being an exception because of the large Western Libya Gas Project, 

which produces 1.0 bcf/d. Prior to 2011, the NOC had 

announced plans to increase the country’s natural gas 

production, including from the Faregh Field operated by Waha in the Sirte Basin and Lellitah’s offshore 

Bouri Field. 

Libyan law requires foreign companies to have a 

local partner, either state owned or private, that owns 

a minimum of 35 percent in any joint venture. There 

are at least 28 IOCs active in Libya.533 Among the more 

important joint ventures are:

1. Waha Oil Company: Consortium of U.S. firms 

ConocoPhillips (16.33 percent), Hess (8.13 percent), 

and Marathon (16.33 percent), in partnership with 

Libya’s NOC (59.16 percent).534 Total capacity is 

350,000 bpd, all from fields in the Sirte Basin. Three 

major growth projects under development by the coventurers include Faregh II, North Gialo, and NC-98. 

535 (Hess is also the 100 percent operator of Area 54 

offshore in the Sirte Basin, where hydrocarbons were 

discovered in 2008.)536

2. Akakus Oil Operations: Led by Spain’s Repsol, 

with 50 percent ownership by the NOC. Production 

capacity about 350,000 bpd; located in the Murzuq 
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Basin. Overall, Repsol has 9 blocks, of which 7 are 

exploratory and 2 are in operation. In January 2011, 

Repsol made a discovery in Block NC-115.537

3. Mellitah Oil & Gas: Led by Italy’s ENI; operations 

in Sirte, Murzuq, and Ghadames Basins. Near Zwara 

in western Libya. Production capacity of 300,000 bpd, 

of which 50,000 is condensate. Was attacked in May 

2013 by militiamen, who stole weapons and military 

vehicles.538

4. Wintershall: This German company, with Russia’s Gazprom and the NOC. Production capacity of 

over 100,000 bpd. Wintershall is currently cooperating with the NOC and Libya’s AGOCO to build a new 

55-km-long oil pipeline to connect the Wintershall 

concession C96 with the Amal field, from which it will 

be exported via the town of Ras Lanuf.539 (Gazprom 

obtained 49 percent shares in Blocks C96 and C97 from 

Wintershall. Gazprom also has Block 19 offshore, for 

which it is preparing drilling, and Block 64, which is 

300 km south of Tripoli in Ghadames Basin.)540

5. Harouge Oil Operations: Led by Canada’s Suncor with a 49 percent interest;541 capacity of about 

100,000 bpd. 

6. Mabrouk Oil Operations: Led by France’s Total 

and NOC, with Norway’s Statoil. Capacity of about 

70,000 bpd. The NC 186 license in the Murzuq area is 

operated by Total and consists of seven fields (A, B, D, 

H, I/R, J, and K).542 (Total also has non-operator shares 

in production in five offshore and three onshore zones, 

and submitted a development plan for Block NC 191 

in onshore Murzuk Basin (100 percent operator).543

For example, Total has a 20.25 percent stake in Block 

C 137, together with Mabruk Oil (73 percent operator) 

and Wintershall (6.75 percent).544

7. Zueitina: U.S. firm Occidental Petroleum and 

Austria’s OMV; in Sirte Basin. OMV acquired 25 
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percent of Occidental’s Libya assets in 1985. In 2008, 

Occidental, OMV, and Libya NOC signed one of the 

biggest redevelopment projects worldwide for these 

mature fields.545 Capacity of about 60,000 bpd. 

8. MedcoEnergi: The Nafusah Oil Operations joint 

venture between this Indonesian IOC (50 percent operator), NOC, and the Libyan Investment Authority 

(50 percent) for Area 47 is one of the few significant 

projects expected to come online over the next 4 years, 

starting in 2016 and peaking production at 50,000 

bpd.546 Eighteen out of 20 exploration wells discovered oil/gas; gross contingent resources of 351.7 million BOE.547 Capacity to be from 50-100,000 bpd. 

9. Other IOCs in Libya include Oil India, which 

has a 50 percent operator interest in onshore Blocks 

86 and 102 (4) and a 25 percent working interest in onshore Area 95/96, Block 2/1, 2, and 4.548 India’s ONGC 

Videsh also has a 49 percent stake in exploration Block 

NC-189 (with 51 percent owned by Turkey’s NOC) 

and Contract Area 43 in the Cyrenaica offshore basin. 

China’s CNPC shares an interest with Libya’s NOC in 

offshore Block 17-4 in the Pelagian Basin off the northwestern coast of Libya, with a water depth of 200-400 

meters.549 Its subsidiary, Greatwall Drilling Company 

(GWDC), is also present in Libya.550 U.S. major ExxonMobil returned to Libya in 2005 after a 25-year absence, winning a license to explore an area covering 

2.5 million acres in the Cyrenaica Basin, one of the 

country’s largest energy fields.551

10. UK/Netherlands major Shell said in November 

2012 that it remained interested in oil and gas exploration opportunities in Libya after abandoning drilling in 

two blocks, LNGDA and area 89, earlier in the year.552

In 2010, the U.S. firm Chevron also did not extend its 

five-year oil and gas licenses in Libya.553 One major 
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concern for IOCs is the possibility of a terrorist attack 

on their facilities, with workers kidnapped or killed, 

such as happened in February 2013 at the Amenas gas 

facility in Algeria. A more likely security problem may 

be in-fighting between militia for influence within the 

government’s Petroleum Facilities Guard.554 Labor 

unrest and protests are other concerns, as protesters 

forced the closure of three major oil terminals in July 

2012, and the Waha Field was blockaded for almost 3 

weeks in March 2013 until the oil minister intervened 

to address the demands of 100 workers.555

Madagascar/France’s Juan de Nova Islands.

Madagascar has five basins, the most important of 

which are the onshore basins of Ambilobe, Majunga, 

and Morondava along the western coast.556 The Ile St. 

Marie Basin on the northern end of the island and the 

Cap St. Marie Basin on the south coast have potential but unproven hydrocarbon systems.557 Political 

instability has been a serious impediment to foreign 

investment in Madagascar’s oil and gas industry and 

only made worse by threats from the transitional government to expropriate major oil fields.558 Madagascar 

has been rocked by political crisis since 2009, when 

Andry Rajoelina ousted President Marc Ravalomanana with the help of dissident soldiers.559 Nevertheless, there were 17 oil companies exploring the island 

as of 2012.560

Onshore. 

Madagascar’s largest oil and gas fields are the Bemolanga and Tsimiroro fields in the Morondava Basin. Rajoelina’s transitional government announced 
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in December 2010 that it was interested in acquiring 

Blocks 3104-3107, where these giant fields are located, 

from the U.S. firm Madagascar Oil at less than market prices.561 The resulting uproar among IOCs led the 

transitional government to delay a planned tender of 

225 offshore blocks in March 2011.562 Later that month, 

Madagascar Oil declared force majeure to safeguard 

its rights under its PSCs,563 eventually forcing the 

government to back down, when it acknowledged 

the firm’s rights under the PSCs for Block 3104 in 

June 2011564 and for Blocks 3105-3107 in April 2012.565

In September 2011, Madagascar Oil increased its estimates for contingent original-oil-in-place (OOIP) 

for Tsimiroro to 1.78 billion barrels.566 The firm has a 

Steam Flood Pilot project at Tsimiroro567 under which 

it will use injected steam into the ground to soften the 

oil, with production starting in 2013 1Q and peaking 

in 2013 4Q or 2014 1Q with 1,000 bpd. Full-scale commercial production at the Tsimiroro heavy oil field 

is expected to commence sometime after 2017 and 

eventually reach peak production of around 160,000 

bpd.568 While Tsimiroro has potential for light oil and 

natural gas, Bemolanga is a field with ultra-heavy oil 

with potential resources of 16.6 billion barrels (about 

9.8 billion barrels of recoverable reserves).569 France’s 

Total has a 60 percent operator interest for an exploration license in Block 3102 (Bemolanga),570 with partner 

Madagascar Oil (40 percent). Total now has the right 

to search for conventional oil as well; it expects first 

production of heavy oil by 2019.571

The UK’s Afren has a 90 percent operator interest 

in Block 1101, which has net prospective resources of 

631 million BOE.572 (Candax owns the remaining 10 

percent.)573 The block is located in the eastern flank of 

the Ambilobe Basin in northern Madagascar, whose 
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southwestern portion is adjacent to Exxon’s Ampasindava Block.574 Australia’s Caravel Energy has a 

25 percent interest in the onshore Behaza Oil Project 

(Block 3114) in the north, with the ability to increase 

its share to 80 percent. Two leads in the block are estimated to contain between 22.1 million and 2.48 billion barrels.575 (The 75 percent owner is reportedly Dr. 

Rsolovoahangy, a Madagascan national.)576 The UK’s 

Avana holds a 100 percent interest in licenses in the 

Sambaina shale oil area of onshore Madagascar.577 Anglo-Irish Tullow Oil two onshore blocks in the southern Morondava Basin,578 Block 3109 (Mandabe license) 

and Block 3111 (Berentry license), for which the firm 

has acquired 2D seismic data and plans for at least one 

well in 2013.579 Mauritius-based, London-listed Essar 

Energy is 100 percent operator of three onshore blocks 

in the Morondava Basin.580

Offshore. 

ExxonMobil operates three blocks inside Madagascar, although it reportedly declared force majeure

in 2009 due to the political situation in the country following a nondemocratic change in government, but 

is considering resuming exploration there, including 

drilling a well in 2013.581 Exxon has a 70 percent interest in the offshore Ampasindava and Ambilobe Blocks 

in the northwest (with 30 percent owned by Sterling 

Energy) and a 50 percent interest in the west-central 

offshore Majunga Block (with 30 percent owned by BP, 

10 percent by Korea’s SK Corporation, and 10 percent 

by NOC PetroVietnam.582 The large Sifaka Prospect in 

Ampasindava has been independently estimated to 

contain gross unrisked best estimate prospective recoverable resources of 1.2 billion barrels.583 Canada’s 
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Niko Resources has the offshore Grand Prix Block584

in west-central Madagascar in the Morondava Basin, 

which is south of Majunga. The onshore part of the 

basin is a proven petroleum province with onshore 

discoveries of oil sands and subsurface heavy oil deposits exceeding 20 billion barrels. The offshore portion of the basin is considered to be part of the same 

petroleum system but extending into a deeper geologic setting that may yield lighter oil discoveries.585

Nigeria’s South Atlantic Petroleum (SAPETRO) has a 

90 percent operator interest in the Belo Profond PSC in 

deepwater Madagascar, in the Mozambique Channel, 

with U.S. partner MAREX owning the remaining 10 

percent.586

France’s Juan de Nova Islands.

In the Mozambique Channel between Mozambique and Madagascar lies the Juan de Nova islands, 

which is controlled by France as part of its TAAF or 

Terres Australes et Antarctique Francaises (French 

Southern and Antarctic Lands) administrative region. 

The islands, which are claimed by Madagascar, were 

not part of Madagascar when the country gained independence in 1960. The Juan de Nova permit, which 

is 75 percent owned by Nigeria’s South Atlantic Petroleum,587 is located east of the Rovuma Basin in 

Mozambique, where Anadarko and ENI have made 

major gas discoveries, and west of Madagascar’s Belo 

Profond permit.588 To the east of the Juan de Nova permit and west of Belo Profond is the Juan de Nova Est 

permit, which was issued by France to the UK’s Wessex (70 percent operator) and Australia’s Global Petroleum (30 percent). France has declared a continental 

shelf surrounding the islands and claims the energy 
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and mineral rights.589 The Juan de Nova Est permit lies 

100 km northwest of the Tsimiroro and Bemolanga 

fields.590

Malawi.

Malawi currently has no oil or gas production, 

but has considerable hydrocarbon prospectivity. The 

government awarded exploration Block 1 in December 2012 to South Africa’s SacOil.591 Block 1 is located 

in northwestern Malawi, bordering Tanzania to the 

north and Zambia to the west. The license is located 

on trend with the East African rift system, which is a 

proven exploration province with prolific oil discoveries in Sudan, Chad, Kenya and Uganda.592 Earlier 

and more controversially, Malawi awarded Blocks 

2 and 3 on Lake Malawi to the UK’s Surestream Petroleum in 2011. Surestream believes its acreage lies 

along the western branch of the East African Rift System, including Uganda’s productive Albertine Basin593

and the Rukwa Block in Tanzania. Since the award, 

Surestream has been conducting an environmental 

survey to establish what impact drilling could have in 

this freshwater lake.594

In 2012, in response to Malawi’s award of Blocks 2 

and 3 to Surestream, Tanzania called on Malawi to stop 

exploring for oil and gas in Lake Malawi (known as 

Lake Nyasa in Tanzania) until a long-standing border 

dispute between the two countries can be resolved.595

Both nations agreed to have the African Forum mediate their dispute,596 but Malawi President Joyce Banda 

reportedly said in April 2013 that her country was 

ready to abandon mediation and take the boundary 

dispute to the International Court of Justice for arbitration.597 Malawi claims sovereignty over the entire 
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Lake based on the 1890 Anglo-German Hligoland 

Treaty, while Tanzania says it is entitled to 50 percent 

of it based on the 1982 UN Convention on the Law of 

the Sea—a battle reminiscent of the dispute between 

Uganda and the DRC following Uganda’s discovery 

of oil on the shores of Lake Albert.598 In January 2012, 

the Tanzanian government awarded the Kyela Block 

in the northern onshore area of Lake Malawi/Nyasa 

to the UK’s Heritage Oil & Gas, and the company continues to analyze 3D seismic data to select targets for a 

drilling program.599

In July 2012, the government also awarded a 100 

percent interest, exclusive prospecting license (EPL 

0360/12) for shale gas and coal-bed methane to Australia’s NuEnergy covering 346 km2

 in southern Malawi near the Mozambique border.600 In May 2013, 

the firm launched its airborne geophysical survey of 

the depth and structure of sediments in the Mwanza 

River Basin.601

Mali.

Mali is largely unexplored for hydrocarbons and 

has no established oil or gas reserves.602 Around onehalf of the country overlies sedimentary basin, but only 

five exploration wells have been drilled—i.e., one well 

per 450,000 km2 of basin.603 The Malian government 

has identified five promising basins: the Taoudeni 

Basin (which extends into Mauritania), the Nara 

Trough (or Nara Graben), the Chad-like Gao Graben, 

the Niger-like and Libya-like Lullemenden-Tamesna 

Basins, and the Algeria-Libya Active Oil and Gas 

Provinces.604

Further exploration in northern Mali is unlikely 

until the country’s political situation stabilizes in the 
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aftermath of three events: a March 2012 coup overturning a series of democratically elected governments; 

the April 2012 takeover of the north by AQIM and 

its Toureg allies; and the January 2013 counterattacks 

by France and its African allies attempting to restore 

democratic, central government control. Reflecting 

concerns about political risk, Italy’s ENI handed back 

to Mali’s government, in January 2013, its licenses to 

explore the north, citing poor prospects. ENI had acquired five Mali licenses in partnership with Algerian 

NOC Sonatrach in 2006.605 Also directly impacted in 

the north are licenses held by Angola’s Petro Plus,606

Canada’s Simba,607 Qatar’s Sphere Petroleum (95 percent interest operator of Blocks 8 and 10),608 and Venezuela’s PDVSA.609

This being said, it is possible that exploration work 

may continue cautiously in southern Mali, which has 

not been affected directly by the terrorist/secessionist groups. Illustrative of this in a different resource 

sector is Canadian gold company Iamgold, which said 

in January 2013 that its operations in southern Mali 

had been unaffected by recent political events, but 

that it would “reduce its exploration activity in the region at this time as a precautionary measure.”610 Two 

IOCs active in the south are Canada’s Petroma, which 

has Blocks 17 and 25 north of the capital Bamako,611

and Bermuda-based AFEX Global, which has carried 

out 2D seismic work in Block 13 north of Petroma’s 

concessions and confirmed that its Block overlies the 

promising Nara Graben, a series of Cretaceous rifts.612

Mauritania.

Mauritania is a frontier exploration country where 

production has been disappointing so far, but where 
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promising offshore and onshore prospects have attracted Asian, Australian, European, and U.S. oil 

firms. The highest profile investor in Mauritania 

has been Malaysia’s Petronas, which bought out the 

47.4 percent share in the offshore Chinguetti oil field 

owned by Australia’s Woodside Petroleum in 2007. 

Petronas is also the operator on the Banda (gas), Tiof 

(oil), and Tevet fields (oil and gas).613 Woodside discovered the Chinguetti offshore field in 2001 and 

started production in 2006 with an estimated reserve 

of 123 million barrels. Production climbed to 75,000 

bpd by late 2006, but “geological difficulties” caused 

production to drop dramatically to 4,000 bpd in 

2011.614 The Banda offshore field, discovered in 2002, 

was declared commercial in 2012, and will supply gas 

to fire an electrical power plant near Nouakchott. The 

Tiof Field, discovered in 2003, is expected to hold 350 

million barrels of oil, while the Tevet Field, discovered 

in 2005, is believed to contain 50 to 100 million barrels 

of oil.615 In 2005, the Faucon Field (gas) was discovered in the south, not far from the maritime border 

with Senegal.616

In 2006, China’s CNPC found hydrocarbons in offshore Block 20,617 for which it has a 65 percent operator 

interest, with Australia’s Baraka Petroleum holding 35 

percent.618 Korea’s Dana Petroleum discovered natural gas at the Cormoran exploratory well in 2010 and 

validated the Pelican gas discovery made 2 km north 

in 2003, both in Block 7. Dana has a 36 percent share in 

Block 7, along with France’s GDF Suez (27.85 percent), 

Anglo-Irish Tullow Oil (16.20 percent), and two Australian firms, PC Mauritania and Roc Oil (15 percent 

and 4.95 percent, respectively).619 In 2011, Anglo-Irish 

Tullow Oil appraised the Pelican gas field and discovered yet another underlying field, Petronia.620 The 
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firm plans a four-well campaign in 2013, starting at 

the Fregate-Scorpion Prospect which could hold 294 

million BOE.621

U.S. firm Kosmos acquired a 90 percent interest 

in three offshore blocks in 2012, with the remaining 

10 percent share held by SMH, Mauritania’s NOC. 

Kosmos, which will start drilling in late 2014, believes 

these blocks are promising because they reside in the 

proven offshore Mauritania salt basin and include cretaceous geological formations that have been productive in Ghana.622 Similarly, the UK’s Chariot Oil & Gas 

acquired a 90 percent share in another offshore block 

in 2012 where petroleum systems are proven and 

plans to drill in 2014. The firm notes that Mauritania 

lies in the Central Atlantic Margin, which opened up 

at same time as the Gulf of Mexico, and also stressed 

that they contain the same geological source rocks as 

found in Ghanaian oil fields.623 In 2012, France’s Total 

acquired deepwater Block C9, which geologically is in 

the Abrupt Margin in which the firm recently made 

major discoveries in French Guyana, and plans to drill 

in 2013 or 2014.624

Onshore, exploration continues in the Taoudeni Basin, in central-eastern Mauritania by China’s CNPC,625

France’s Total, Germany’s RWE,626 and Spain’s Repsol.627 Total’s partners include Algeria NOC Sonatrach 

and Qatar Petroleum International.628 Even if commercial discoveries are made, however, the current political uncertainty caused by the presence of AQIM in 

neighboring Mali may deter onshore development, as 

adherents of this group have also carried out attacks 

in Mauritania. 
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Mauritius.

Mauritius has no known oil or gas deposits. The 

government has engaged in talks with other nations, 

including India in 2003 and 2007, about concluding 

Memoranda of Understanding for cooperation in offshore oil and gas exploration. Nearly 70 percent of the 

Mauritius population is of Indian origin, and the two 

nations have a special relationship because of this.629

Indian oil company ONGC has sought oil and gas exploration rights in Mauritius.630

Morocco.

Compared to its prolific oil and gas producing 

eastern neighbor Algeria, Morocco has had a modest 

upstream industry.631 Morocco has a variety of liquid 

and dry accumulations “ranging from dry gas in the 

Gharb (also known as Rharb) Basin, condensate in Essaquira, light oil in Essaquira and Prefi, to heavy oil 

in Tarfaya.”632 The most important oil and gas fields 

currently in production are the Essaouira Basin on the 

coast, producing oil and natural gas, and the Gharb 

Basin in the north. Ireland’s Circle Oil is drilling six 

wells in Sebou and Lalla Mimouna, in the Gharb region633 south of Tangiers and near the Strait of Gibraltar. An important gas field was also discovered in recent years at Meskala, just north of Essaouira, where 

condensate has been produced since 1987.634 There 

are even unconventional oil shale formations being 

developed by Ireland’s San Leon Energy onshore in 

southwest Morocco at Tarfaya635 and at Tmahdit in the 

middle Atlas Mountains.636

Despite the E&P, most sedimentary basins in 

Morocco onshore and offshore are still largely un-
190

explored. Several factors created enthusiasm among 

IOCs for Morocco’s oil and gas potential, particularly 

in 2012 and so far in 2013: the government’s stability, 

its competitive taxation regime, a supportive regulatory framework; and a capable NOC partner, ONHYM.637 Leveraging its deepwater expertise, U.S. giant 

Chevron acquired rights in January 2013 to 75 percent 

of three offshore areas in Morocco: Cap Rhir Deep, 

Cap Cantin Deep, and Cap Walidia Deep.638 Moroccan 

NOC ONHYM retained 25 percent shares for both the 

Pura Vida and Chevron deals. U.S. firm Kosmos has 

acquired operator shares in four offshore blocks, three 

in the Agadir Basin, and the fourth in the Aaoun Basin. 

It plans exploratory drilling as early as the second half 

of 2013.639 Kosmos increased its equity shares in two of 

these blocks and now has 56.25 percent participating 

interest in the Foum Assaka Block and a 75 percent 

interest in the Essaouira Block.640 In January 2013, U.S. 

firm Plains Exploration and Production (PXP) purchased a 52 percent operator interest in the Mazagan 

permit from Pura Vida. PXP expects to drill the first of 

five wells in 2014 in the Toubkal Prospect, which has a 

mean resource potential of 1.5 billion barrels.641

Current IOCs active offshore and/or onshore in 

Morocco include Australia’s Pura Vida Energy, Tangiers Petroleum, and Triangle Energy; Portugal’s Galp 

Energia, and the UK’s Caithness Petroleum, Cairn 

Energy, Chariot Oil, Genel Energy, Gulfsands Petroleum, Longreach Oil & Gas, and Serica Energy.642 In 

2010 and 2011, Spain’s Repsol acquired four offshore 

and onshore exploratory licenses at Tangers-Larache, 

Gharb Offshore, Hauts Plateaux, Boudenib.643 New exploration is taking place offshore within the Atlantic 

Basin and the Mediterranean Sea at Casablanca Offshore, Loukos Offshore, Rabat Deep Offshore, Gharb 
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Offshore, Tanger-Larache, and onshore at Boudenib, 

Fes, Foum Draa, Haut Plateaux, Oulad, Safi, Sidi Moktar, Sidi Moussa, Taounate, Tarfaya, Zag, and N’zala.644

Mozambique.

Mozambique has two main sedimentary basins: 

the Rovuma Basin in the northeast adjacent to the 

Tanzanian border and the Mozambique Basin in the 

south.645 Mozambique estimated that it may receive 

$50 billion in investment by IOCs to develop the 

country’s new gas fields,646 which are concentrated in 

Rovuma. 

Offshore.

Since signing an oil and natural gas Exploration 

and Production Concession Contract (EPCC) with 

Mozambique in 2006 for Area 1 in the Rovuma Basin, 

Anadarko and its partners have safely drilled more 

than a dozen deepwater wells within the Offshore 

Area 1 Block, discovering an estimated 35 to 65+ tcf of 

recoverable natural gas (approaching 100 tcf of original gas in place [OGIP]). Six of the discovery wells 

in the Prosperidade and Golfino/Atum compexes 

(Windjammer, Barquentine, Lagosta, Camarão, Golfhino and Atum) were among the largest discoveries in 

all of Africa during 2010, 2011, and 2012, according to 

IHS Energy. Additionally Anadarko and its partners 

are now advancing a commercial LNG development 

that is initially expected to consist of four liquefaction trains (5 million tons per annum [mpta] each).647

Anadarko is now evaluating a third discovery in the 

block, Tubarao, and will drill an appraisal well there 

in 2013. Overall, Area 1 is among the world’s most significant hydrocarbon finds in the last decade.648
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Early in 2013, Anadarko and ENI reached an 

agreement as operators to conduct separate, yet coordinated offshore development activities, while jointly 

planning and constructing common onshore liquefaction facilities in the form of an LNG park in the Cabo 

Delgado province of northern Mozambique649 with a 

capacity of approximately 50 million tons of LNG per 

year—enough to elevate Mozambique to one of the 

world’s largest LNG exporters.650 Reflecting its need 

to seek massive financing to develop these fields and 

its share of the LNG park, Anadarko said that the firm 

was considering selling up to one-third of its interest 

in the block.651 NOC Oil India and India’s ONGC reportedly made a joint offer for a 20 percent stake in 

Offshore Area 1.652 In March 2013, Anadarko was also 

talking with potential Japanese off-take customers for 

its LNG production.653 Anadarko operates Area 1 (36.5 

percent interest) with Japan’s Mitsui (20 percent), India’s BPRL Ventures and Videocon (10 percent each), 

Thailand’s PTTEP (8.5 percent), and Mozambique’s 

NOC ENH (10 percent).654 The presence of Mitsui, a 

Japanese general trading company (sogo shosha), as a 

partner makes it more likely that the consortium will 

ultimately find Japanese off-take customers, and that 

Anadarko will not sell out its share to a Chinese NOC. 

Like Anadarko, Italy’s ENI has also enjoyed great 

success in the Rovuma Basin. ENI made a new discovery in December 2012 in the Mamba Complex of the 

Offshore Area 4, which is due east of Area 1,655 bringing its estimate for gas in place at 75 tcf. Its operator 

interest is 70 percent, with 10 percent each for Portugal’s Galp Energia, South Korea’s KOGAS, and ENH.656

In March 2013, ENI reached an agreement to sell 

Chinese NOC CNPC a 28.6 percent share of its ENI 

East Africa subsidiary for $4.21 billion,657 and there-
193

fore a 20 percent interest in Area 4.658 The presence of 

CNPC and KOGAS make it more likely that Asian offtake customers for this consortium’s gas production 

will be from China and South Korea, respectively. 

Due south of offshore Areas 1 and 4 are offshore 

Areas 2 and 5, still in the Rovuma Basin, and operated by Norway’s Statoil (40 percent share) with Japan’s Inpex (25 percent), Anglo-Irish Tullow Oil (25 

percent), and ENH (10 percent).659 The partners plan 

to drill two wells in 2013 2Q.660 In the author’s view, 

Statoil selected Inpex as a strategic partner, in April 

2013, to facilitate long-term gas contracts with Japan. 

Due south of Areas 2 and 5 are Offshore Areas 3 and 

6, operated by Malaysia’s Petronas (50 percent share), 

with French partner Total (40 percent) and ENH (10 

percent). “The oil potential of the southern part of 

the Rovuma Basin might equal the gas potential of 

the northern part,” a Total spokesman has asserted,661

suggesting that Areas 2, 3, 5, and 6 could be the site of 

future large discoveries. 

Onshore. 

Mozambique currently has four onshore fields: 

Pande, Temane, and Buzi-Divinhe,662 all discovered 

in the 1960s, and Inhassoro, discovered by South Africa’s Sasol in 2003.663 Starting in 2004, Sasol exported 

most of its output through an 865-km pipeline to its 

South African chemical plants. It currently plans to 

increase production to supply its expanded synthetic 

fuels plant in South Africa and a new gas-fired power 

plant in Mozambique. Production of natural gas from 

the Pande and Temane fields, operated by Sasol, increased to about 3.1 bcm in 2010.664 In July 2012, Sasol 

was analyzing the feasibility of developing the con-
194

densate deposit, with a potential of 215 million barrels, which it recently discovered in Inhassoro.665

Anadarko is lead operator (35.7 percent) of Rovuma Onshore on the Tanzanian land border adjacent to 

the Indian Ocean, with France’s Maurel et Prom (27.7 

percent), ENH (15 percent), the UK’s Wentworth (11.6 

percent), and Thailand’s PTTEP (10 percent).666

Further opportunities exist onshore in the provinces of Gaza, Inhambane, Sofala, Zambezia, Nampula, and Cabo Delgado.667 Several oil companies are 

also carrying out exploration activities in the Urema 

Graben in central Mozambique, which is the southern 

part of the East African Rift System.668

Governance Challenges.

Excluding onshore natural gas reserves and the 

potential for unconventionals such as coal-bed methane, Mozambique may already have 175 tcm of gas 

between the discoveries to date in Areas 1 and 4. By 

one estimate, Mozambique, which already grew by 

7.9 percent annually from 2001 to 2011, may double 

or triple its GDP over the next 20-30 years. Yet, just as 

geological risk for Mozambique is declining, “the political, regulatory, and infrastructure risks are increasing,” likely leading to delays in the 2018 start-up for 

bringing new offshore gas fields to production.669 On 

the surface, Mozambique is politically quite stable, 

with the same ruling party, Frelimo, in power and 

winning by big margins at the polling place since independence from Portugal in 1975. However, a gas and 

coal boom has raised public expectations in a country 

where income inequality and poverty level have not 

improved despite rapid economic growth. There were 

two bouts of urban unrest in Maputo in 2008 and Tete 
195

Province in 2012. Also problematic are regulatory

gaps in existing oil and gas legislation. One academic 

felt that the Mozambique government: 

urgently needs to clarify its broader development 

agenda for the gas sector and make crucial decisions 

around infrastructure, local gas pricing, capital gains 

taxes, corporate and social responsibility standards, 

and social fund payments.670

In December 2012, the government was considering levying a 32 percent tax on future sales of local 

assets,671 which could discourage farm-outs to and 

risk-sharing with Asian IOCs. Also discouraging future farm-outs is a proposal to increase in the government’s share (though NOC ENH) in oil and gas blocks 

to a maximum of 40 percent, up from the current of 25 

percent.672 The Mozambique government announced 

in May 2013 that it expected its new petroleum law to 

be ratified by year-end 2013 in time for a new licensing 

round to promote exploration in offshore areas 4, 5, 

and 6. The government also claimed that it was moving closer to developing a master plan for the development of its new natural gas discoveries, including 

asset development options, optimal locations, pricing 

structures, and social improvements. Besides the LNG 

park, options include fertilizer, petrochemical, gas-toliquids, and power generation.673

On a positive note, in December 2011, the Mozambique government did sign an agreement with 

Comoros and Tanzania, demarcating their land and 

maritime borders.674
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Namibia.

Offshore.

Namibia has attracted investment by major IOCs 

in 2012, including the UK’s BP,675 Portugal’s Galp,676

and Spain’s Repsol,677 on the bet that its coastal shelf 

may mirror that of Brazil across the Atlantic Ocean, 

where the Tupi discovery in 2007 was the biggest find 

in the Americas in 3 decades.678 Namibia and Brazil 

are on the opposite sides of the South Atlantic Margin 

and share geological history—leading one observer to 

assert boldly that “Namibia is due to become one of 

the largest energy producers in Africa [and] might be 

positioned to rival its neighbor Angola and Algeria in 

North Africa.”679

There are four offshore basins in Namibia that are 

the focus of interest: the Namibe Basin in the north, 

which starts south of the Angolan border and part of 

the prolific West African “salt basin.” Prior to the Atlantic Ocean opening, the Namibe Basin lay adjacent 

to the Santos Basin of Brazil, where super-giant oil 

discoveries have been made. The central Luderitz and 

Walvis Basins are virtually unexplored, with only four 

wells drilled as of the end of 2012. To the south, the 

Orange Basin includes the large delta of the Orange 

River system and holds the Kudu gas field,680 which 

was discovered by Chevron in 1973,681 and whose 

production will be exported to South Africa,682 or sold 

to NamPower, a Namibian utility.683 Significant new 

exploration is being undertaken in the Kudu field in 

a joint venture led by Anglo-Irish operator Tullow 

Oil, with Russia’s Gazprom, Japan’s trading house 

Itochu, and Namibia’s NOC.684 Brazil’s HRT Oil holds 

10 offshore blocks in four licenses and drilled its first 
197

exploratory well in License 23 offshore in Walvis 

Bay in March 2013,685 with a second planned for June 

2013. Although HRT did not find oil in commercially viable quantities, the firm indicated that the well 

“confirms the oil potential of the basin” and “most 

thought Namibia would only be a [natural] gas potential area.”686 Other companies exploring for oil and 

gas offshore include Australia’s Global Petroleum687

and Pancontinental,688 Canada’s Eco Oil & Gas689 and 

Westbridge Energy,690 France’s Maurel et Prom,691

Nigeria’s Oranto,692 South Africa’s Signet Petroleum,693

the UK’s Serica Energy694 and Tower Resources,695 and 

U.S. firm EnerGulf Resources.696 Pancontinental announced that it had received an independent Mean 

Prospective Resource estimate for its EL0037 petroleum license of 8.2 billion barrels of oil.697 Westbridge, 

which has an 80 percent share in 1811B and is acquiring a 75 percent interest in adjacent 19-series blocks 

from Nambian private-sector company Ropat Petroleum Investments, believes that its licenses: 

show similar geologic play concepts and trends to 

those observed in other prolific petroleum basins in 

Brazil and the deepwaters of Ghana, Angola, Liberia 

and Sierra Leone.698

Global, which holds an 85 percent interest in 

PEL-29, has noted evidence of hydrocarbons, including oil slicks on the ocean floor, seabed cores, 

and 2D seismic, and is believed to have two prospects with greater than one billion barrels each of 

recoverable oil.699

In 2011, the Ministry of Mines and Energy announced that a study had identified the potential for 

some 44 billion barrels of oil offshore,700 and claimed 
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that 11 billion barrels in oil reserves had already been 

found.701 He predicted first production by 2015, a date 

that seems likely to slip in the light of three dry wells 

in 2012, one by Petrobras in the southern Orange Basin702 and two by Chariot, one in a southern block and 

the other in a northern block.703

A major reason for a lack of exploration offshore 

has been the significant, expensive challenge of the 

depths at which prospective fields are thought to be 

located. In Angola, to the north of Namibia, initial 

offshore success was in much shallower waters and 

paved the way for majors to go after promising structures in deeper water.704 By contrast, in Namibia, there 

had only been 15 offshore wells ever drilled as of 2011 

3Q, meaning that the geology is less well known. 

Chariot’s failed effort to drill in the northern block at 

the Tapir Prospect to 4,879 meters in 3,123 meters of 

water reportedly cost the company $65 million.705

Onshore.

Three U.S. firms, Duma Energy,706 Frontier Resources,707 and HydroCarb, have encountered promising 

signs of hydrocarbons in the Owambo (Etosha) Basin 

in north-central Namibia bordering on Angola—one 

of the largest, unexplored onshore basins in Africa.708

HydroCarb’s COO believes that the “Owambo Basin 

has all the ingredients to become a major new hydrocarbon province.”709 Frontier Resources has Blocks 

1717 and 1817 in the eastern sector of the Owambo 

Basin, where Occidental Petroleum found evidence 

of a petroleum system in 1993-94.710 Frontier believes 

that the East African Rift System has an extension into 

northeast Namibia.711 Smaller independent oil companies such as the UK’s Chariot Oil & Gas and Tower 

Resources, Brazil’s HRT, and Canada’s Eco Oil & Gas 
199

have licenses with shale and coal-bed methane potential, particularly in the Nama/Karoo Basin,712 which 

extends into Botswana and South Africa. 

Niger. 

Niger has three distinct areas of oil and gas 

potential:

1. Agadem Block: Currently the country’s only 

producing block. It covers the southern half of the 

Termit-Tenere Rift, bordering Chad to the east. The 

Niger government estimates the proven oil reserves in 

Agadem at 324 million barrels, but has also reported 

that oil reserves could prove to be three times higher 

than this number.713

2. Tenere Block: Comprises the northern part of the 

Termit-Tenere Rift, which is one of several rift basins 

that extend across north-central Africa with similar 

oil-producing basins found in Libya, Chad, and Sudan. Thought to possibly hold 1-3 billion barrels of 

oil.714

3. Kafra Block: A continuation of the rift basin of 

the Tenere Block; situated in northern Niger up to the 

Algerian border.715 Algerian NOC Sonatrach is exploring in this block.716

In Agadem, China’s CNCP took over in 2003 from 

an ExxonMobil/Petronas joint venture that was not 

renewed, taking a 100 percent share in Block Bilma 

and an 80 percent share in Block Tenere, along with a 

Canadian oil company, TG World, which took 20 percent. In 2008, Niger and CNCP signed an integrated 

upstream/downstream package concerning exploration and development of the Agadem Block, and 

construction and operation of both a long-distance 
200

pipeline and a joint venture refinery. The integrated 

project became operational in 2011 with a 1 metric ton 

per year (mt/y) oilfield, a 1 mt/y (20,000 bpd) refinery near Zinder, and a 462.5-km oil pipeline to connect 

the oilfield and refinery.717 In an interesting example 

of warming cross-Straits economic ties, CNCP agreed 

in April 2013 to a joint exploration agreement for the 

Agadem Block with Taiwan’s NOC, CPC.718

Instability in neighboring Mali to the west notwithstanding, IOCs are still interested in Niger, particularly in the eastern part of the country. In 2011, 

Russia’s Gazprom reportedly was going to undertake 

both mining and oil/gas exploration in the Agadez region.719 In November and December 2012, Australia’s 

International Petroleum720 and Canada’s Brandenburg 

Energy721 picked up four leases each. 

Chad-Cameroon Pipeline. 

In a move to ensure an export outlet, the Niger 

government signed an agreement with Chad in July 

2012 to construct a 600-km pipeline linked to the 

Chad-Cameroon pipeline. Niger is expected to begin 

producing oil at four fields in its Agadem Block by 

early 2014, with production increased to 80,000 bpd, 

20,000 of which would be processed at the refinery 

near Zinder and 60,000 bpd exported through the 

pipeline.722

Nigeria.

The outlook for OPEC member Nigeria, which is 

both Africa’s largest oil producer and holder of its 

largest oil reserves, hinges on resolving a number 

of major issues, including civil conflict in producing 

regions; improving the transportation infrastructure, 
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whose deteriorated state has led to sporadic disruptions to supply; the inability of the Nigerian National 

Petroleum Company (NNPC) to fund its share of investment in joint ventures with IOCs;723 and delays in 

agreeing to a new Petroleum Industry Bill, which is 

holding back $40 billion in investments in the energy 

sector.724 ConocoPhillips’ pessimistic view of Nigeria’s 

investment environment was a significant factor behind the $1.79 billion sale of its Nigeria assets in January 2013 to Oando Energy Resources, a Nigerian company.725 Similarly, Chevron’s May 2013 decision to sell 

its 40 percent undeveloped stake on OMLs 83 and 85 

has to be seen as a divestment vote of no confidence, 

given the firm has put off a decision to develop them 

despite estimates that two fields, Anyala (in OML 

83) and Madu (in OML 85) are thought to have combined reserves of about 250 million barrels and 500 bcf 

of gas.726

Despite new output from deepwater fields, 

Nigeria’s production declined slightly in 2012 from 

the previous year as increased oil theft727 and flooding cut crude oil production in the fourth quarter by 

about 200,000 bpd. Incidents of oil theft and pipeline 

vandalism continue to curb production in 2013. Crude 

oil output averaged 2.0 million bpd in the first quarter of 2013, which is 120,000 bpd lower than the same 

time period last year, despite new production coming 

online. This is also well below the country’s 3.0 million bpd capacity.728 EIA expects crude oil production 

to remain relatively flat in 2013 compared to the previous year, although one investment house predicted 

an increase to 2.3 million bpd.729 Nigeria’s oil industry 

is primarily located in the Niger Delta, where local 

groups seeking a share of the oil wealth often attack 

the oil infrastructure and staff. Current exploration is 
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mainly focused on deep and ultra-deep offshore.730 The 

Bonga Field (OML 118) is Nigeria’s first deepwater oil 

field; it began production in 2003 and is responsible 

for about 600,000 bpd out of the country’s 2.0 million 

bpd in production. Other major oil and gas fields include Akpo, located off the coast of Port Harcourt, and 

Agbami, located offshore in the central Niger Delta. 

In 2011, Anglo-Dutch Shell had the largest daily 

production among IOCs (974,000 bpd), followed by 

ExxonMobil (800,000 bpd, of which 700,000 bpd is 

crude), Chevron (516,000 bpd),731 and Total (which 

produced 179,000 bpd before selling some of its interests to Chinese IOCs). By another calculation, 

Shell (and its joint venture partners, including NOC 

NNPC) accounted for 26 percent of Nigeria's crude oil 

production in 2011, while the comparable figures for 

ExxonMobil were 25 percent, Chevron 22 percent, and 

Total 12 percent,732 all including the shares of their respective partners.733 The remaining unaffiliated firms 

only accounted for 15 percent of Nigeria’s oil production in 2011. One example of several smaller U.S. independents with operations in Nigeria is CAMAC Energy, which has an interest in a PSC for OML 120 with 

operator ENI of Italy. 

China’s CNOOC and Sinopec have managed to 

acquire 209,000 bpd production in Nigeria by buying producing assets rather than participating in bid 

rounds, making China the fifth-largest IOC producer 

in the country after Shell, ExxonMobil, Chevron, and 

Total.734 CNOOC and Sinopec did this through a series 

of acquisitions starting in 2006 with CNOOC’s $2.268 

billion purchase of 45 percent of OML 130, which is 

operated by Total, and CNOOC’s purchase of 38 percent of Stubb Creek (OPL 229), a 15 million barrel field 

owned by Nigeria’s Universal Energy. In 2008, Sinopec 
203

took over the operatorship of NPDC’s OML 64 and 66, 

and in 2009 took over Addax, the largest international 

independent operating in Nigeria.735 As mentioned 

earlier, in November 2012, Sinopec also purchased a 20 

percent stake from Total in the Usan Field (OML 138/

OPL 222), which started production in 2012. CNCP 

used a different approach to enter Nigeria. In 2006, 

CNPC reached an oil and gas cooperation agreement 

with the government of Nigeria and won the tender 

of four blocks, namely OPL298, OPL471, OPL721, and 

OPL732. Block OPL298 and Block OPL471, of which 

one is onshore and the other offshore, are located in 

the Niger Delta. Block OPL721 and Block OPL732, 

the latter a risk exploration block, are located in the 

Chad Basin in Borno Province, northern Nigeria.736 As 

discussed previously, China also indirectly acquired 

Nigerian oil and gas assets through its acquisitions of 

two Canadian energy companies, Addax and Nexen. 

Among other BRIC countries, India’s ONGC Videsh 

had shares in deepwater Blocks OPL 279 and OPL 285 

(45.5 and 64.33 percent operator shares) and a 13.5 

percent non-operator share in the Nigeria-Sao Tome 

& Principle JDZ Block 2.737 Oil India had a 17.5 percent 

non-operator share in onshore OPL 205.738

Nigeria is notable in having a significant number 

of indigenous oil companies, including SAPETRO and 

Oando, which also have operations in other African 

countries.739 Part of the reason for this phenomenon 

is the Nigerian government’s policy of encouraging 

foreign companies to establish partnerships with local Nigerian oil companies under the indigenous and 

marginal field programs. Canada’s Mart Resources is 

an example of a small IOC independent which has created an investment niche for itself in Nigeria under 

this program.740
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The following oil projects are planned to come online in the next few years, although several are likely 

to be delayed pending passage of the Petroleum Industry Bill and resolution of other regulatory issues:

Source: “Nigeria,” EIA Country profile, October 16, 2012.

Table A-I. Upcoming Oil Projects in Nigeria.

New output from deepwater fields could increase 

production in 2014, but this depends on unplanned 

disruptions, which could continue to offset new proProject Capacity 

('000 bpd) Est. Start-up Sector Operator

Agbami 100 2011-14 deepwater Chevron

Ebok (phase 2) 35 2012 offshore Afren

Gbaran Ubie 70 2012+ onshore Shell

Ehra North 

(phase 2)

50 2013+ deepwater ExxonMobil

Oberan TBD 2013+ deepwater ENI

Ofon (phase 2) 90 2014 offshore Total

Aje TBD 2014 deepwater Yinka Folawyo

Bonga North, 

Northwest

50-150 2014+ deepwater Shell

Bonga Southwest 

and Aparo

140 2014+ deepwater Shell

Egina 150-200 2014+ deepwater Total

Bosi 135 2015 deepwater ExxonMobil

Nsiko 100 2015+ deepwater Chevron

Uge 110 2016 deepwater ExxonMobil

Nkarika TBD 2019 offshore Total

Etan/Zabazaba 110 TBD deepwater ENI

Okan 25 TBD offshore Chevron
205

duction gains, and whether projects come on stream 

as scheduled.741 A group of IOCs have said that Nigeria’s plan to achieve 4 million bpd production and 40

billion barrels in reserves by 2020 is unrealistic under 

the new fiscal terms being proposed by the federal 

government in the draft Petroleum Industry Bill being considered by Parliament.742 One prediction by respected oil industry consultants Wood Mackenzie indicated that Nigeria’s oil production could fall to 1.84

million bpd by 2020 because of aging onshore fields, 

and insufficient investment in new offshore projects 

to compensate due to a negative investment climate.743

Despite this pessimism, ExxonMobil has decided to 

press on with its Erha North offshore project. 

In addition to oil, Nigeria holds the largest natural gas reserves in Africa at 180 tcf (as of the end of 

2011), but has limited infrastructure in place so far to 

develop the sector and only produced one tcf of dry 

natural gas in 2011.

744 A major Nigerian government 

priority is to advance the Brass LNG project,745 the second LNG project after the NLNG project, which was 

started in 1999 and has Nigeria’s NOC as its operator. 

The government has been working for several years to 

end natural gas flaring, but the deadline to implement 

its 2009 Gas Master Plan has been delayed repeatedly, 

in significant part because security risks in the Niger 

Delta have made it difficult for IOCs to construct infrastructure that would support gas monetization. 

A significant portion of Nigeria’s marketed natural 

gas is processed into LNG. In 2010, Nigeria exported 

875 bcf of NLG, making it the fifth largest LNG exporter in the world. Nigeria also began to export some 

of its gas in 2010 via the West African Gas Pipeline to 

neighbors to the west: Benin, Togo, and Ghana. The 

pipeline is owned by Chevron (36.7 percent), Nige-
206

ria’s NOC (25 percent), and Shell (18 percent), with 

the remainder held by state-owned shareholders from 

Ghana, Togo, and Benin. Chevron also operates the 

Escravos Gas-to-Liquids project, which is scheduled 

to be operational by 2013.

746

Inland Offshore.

The Nigeria National Petroleum Corporation 

(NNPC) announced in September 2012 that it had discovered oil in the Nigerian territorial waters of Lake 

Chad, which it shares with neighbors Cameroon, 

Chad, and Niger. USGS estimates that the region of 

Lake Chad holds 2.32 billion barrels of oil and 369 bcm 

of natural gas.747 NOC Oil India has a 25 percent share 

in OML 142.

748

Rwanda.

Rwanda has no oil production,749 but does have 

methane gas reserves along its borders with the DRC 

and Tanzania that are being developed. Three oil and 

gas developments in Rwanda of note are 1) ongoing

oil and gas exploration by Canada’s Vanoil, 2) an 

under-construction methane-powered electricity 

project at Lake Kivu undertaken by U.S. investment 

firm Contour Global, and 3) an African Development 

Bank-funded feasibility study that could lead to the 

construction of a regional pipeline. 

1. Exploration in Lake Kivu. Vanoil has a technical evaluation agreement with Rwanda’s government 

covering approximately 1,631 km2

 in the northwestern part of Rwanda, best known as the East Kivu 

Graben, located beneath Lake Kivu. Under the agreement, Vanoil must place its first two wells anywhere 
207

within Blocks 3A and 3B by July 31, 2013.750 The Kivu 

Graben area is part of the East African Rift System 

and is approximately 90 km wide and 200 km long. 

The graben straddles both Rwanda and the DRC 

and is the southern extension of the Albertine Graben in Uganda, where one billion barrels have been 

discovered by Anglo-Irish Tullow Oil and the UK’s 

Heritage Oil. Vanoil believes that Lake Kivu’s common origin (shared tectonic and sedimentary in-fill) 

with Lake Albert, Lake Edward, and Lake George 

make this a promising region for exploration. Vanoil, 

through contractors, has completed both an aerial 

survey of the earth’s gravity and magnetic fields over 

Lake Kivu and southwest Rwanda, and a 2D marine 

seismic survey.751

2. Methane-Powered Electricity. Kivuwatt Ltd., a 

subsidiary of sustainable development-focused Contour Global of the United States, is building facilities 

in Rwanda to extract natural gas from Lake Kivu and

pipe it to a new gas-fired power station. State-owned 

Kubuye Power already extracts methane gas from the 

lake, which is used to feed a 4.2 megawatt power station.752 In 1936, naturally occurring methane was first 

discovered in Lake Kivu, which in 1976 was estimated 

to contain a 55-60 km3

 field with an increasing quantity of trapped methane gas. In the project’s first phase, 

processed methane gas will produce approximately 25 

megawatts (MW) of electricity; phase 2 is expected to 

add another 75 MW of capacity, all for the local Rwandan 

power grid.753

3. Regional Pipeline. The East African Community 

(EAC) Secretariat has announced that it has funding 

for a pipeline south from Rwanda to Burundi, but 

needs ADB funding and support for a second, new 

pipeline linking Rwanda to an existing pipeline be-
208

tween Kampala, Uganda, and Eldoret, Kenya. A feasibility study carried out in 2007 indicated that the 

Kigali-Kampala pipeline was commercially viable and 

would cost $193.6 million to build.754

Sao Tome and Principe.

To date, there have not been any major commercial 

oil or gas finds in Sao Tome and Principe, but there is 

guarded optimism about future discoveries. Three oil 

and gas stories for Sao Tome and Principe concern 1) 

E&P in the Joint Development Zone (JDZ) with Nigeria; 2) E&P in Sao Tome’s EEZ; and 3) plans to build a 

tank farm and oil transshipment port for international 

use firms operating in the Gulf of Guinea sub-region. 

JDZ.

Sao Tome and Nigeria signed a treaty in 2001 to 

create the JDZ, divided it into nine blocks in 2003, and 

solicited bids in a first licensing round in 2004. Sao 

Tome has a 40 percent share in the JDZ, and Nigeria 

has a 60 percent share. The Joint Development Authority, created under the treaty, awarded U.S. firms 

Chevron and ERHC exploration rights, respectively, 

for Block 1 in 2004 and Blocks 2 to 6 in 2005.755 (ERHC 

currently also has a 20 percent share in Block 9.) Block 

1, located in 1,600 to 1,800 meters in water depth, is 

the most promising and is operated by France’s Total, which purchased Chevron’s 49.5 percent stake in 

2010 in order to create cost and operational synergies 

between Block 1 and its stake in the adjacent Nigeria 

Block 248.756 Other shares in Block 1 are Chinese owned 

Addax, South Africa’s Sasol, Nigeria’s Dangote Energy, and UK-firm Afren/DEER. Obo-1, drilled in 2006 
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in Block 1, proved a working hydrocarbon system in 

the JDZ,757 but Total’s Obo-2, drilled in May 2012, was 

plugged and abandoned.758 Total continues to evaluate commercial viability of the Obo Field.759 “At all of 

the wells so far drilled in the Joint Zone, hydrocarbons 

have been found—either gas or oil—but the question 

is if these deposits do or do not have a commercial 

value,” the JDZ’s Executive Director said in August 

2012. One interesting element of the JDZ has been the 

Asian presence of China’s Sinopec, which has operated Block 2: Addax, a firm bought out by Sinopec in 

2009, which operates Blocks 3 and 4; and an Indian oil 

firm, ONGC Videsh, which has written off its 13.5 percent share in the up-to-now disappointing Block 2.760

Hong Kong-based private company Sinoangol (not 

to be confused with China Sonangol) has applied for 

exploration rights in Block 2.761

EEZ.

The EEZ covers an area of 160,000 km2 south and 

east of the JDZ. The STP government launched bidding for 9 of 17 blocks in its EEZ in 2010. Because of 

limited success in the JDZ, there were no major international oil companies who bid on the blocks, which 

were awarded, inter alia, to smaller African oil producers: Nigeria’s Oranto Petroleum, Angola’s Grupo 

Gema, South Africa’s Afex,762 and OG Engineering of 

STP. The STP government later awarded 100 percent 

interests to U.S. firm ERHC Energy (in Blocks 4 [zone 

A] and 11 [Zone B]) and UK firm Equator Exploration 

(in Blocks 5 [Zone A] and 12 [Zone B]).763 (Nigeria’s 

Oando Ltd. purchased a majority stake in Equator in 

2011.764) ERHC believes that the close proximity of 

STP’s offshore waters to the proven hydrocarbon sys-
210

tems in the adjacent territorial waters of Gabon, Cameroon, Equatorial Guinea, and Nigeria suggest the 

potential for hydrocarbons. The firm believes that the 

EEZ has “all the necessary components of a successful 

petroleum system.”765

Tank Farm /Oil Transshipment Port. 

Sao Tome plans to build a refined petroleum tank 

farm, financed by the Nigerian government. The 

farm would: 

serve as a refined petroleum transfer center for Nigeria and other Gulf of Guinea ports which suffer from 

port backlogs. This would allow larger ocean-going 

vessels to offload at the tank far and for subsequent 

transfers to final West African destination by smaller 

vessels or barges.766

The STP government signed a contract with Swiss 

firm Gunvor to construct a $200 million dollar port on 

the north side of the island of Sao Tome.767

Senegal.

The main oil and gas E&P areas in Senegal are in 

offshore blocks in Senegal’s territorial waters or EEZ 

and in Senegal’s JDZ with Guinea-Bissau. 

Offshore and Onshore Senegal.

Offshore exploration in Senegal started in the late 

1970s, resulting in one field of heavy crude oil and 

one gas field (Daim Niadio 14). Senegal has 19 blocks, 

running from Block A (Saint Louis Offshore Deep 

in the north) to Block S (Casamance Onshore in the 
211

south), of which 10 are offshore and 9 onshore. The 

only hydrocarbon production in Senegal at present is 

from the Gadiaga Field, about 60 northeast of Dakar, 

which is shared 70 percent by Houston-based Fortesa 

and 30 percent by NOC Petrosen. Fortesa also has a license to explore the Tamna (Zone G) onshore block.768

Other foreign investors in Senegal’s oil & gas industry 

include Nigeria’s Oranto, which has PSCs for three 

blocks.769 Senegal’s total annual crude oil production 

was 99,000 bbl in 2008, 249,000 bbl in 2009, and 398,000 

bbl in 2010.770

Anglo-Irish Tullow operates the 2,807 km2 Saint 

Louis offshore block (Zone B) in the north with a 60 

percent interest. Tullow is optimistic about further exploratory drilling in 2013 because of the results of a 

seismic survey carried out on the boundary between 

Senegal and Mauritania in 2008, and an exploratory 

well drilled in 2011 in the same Cretaceous turbidite 

play that led Tullow to discover the Jubilee Field in 

Ghana. This license covers the northern-most inshore 

section of the Saint Louis offshore area and adjoins 

Mauritanian Block 1, where Tullow also has nine contiguous licenses.771 The UK’s Cairn Energy (operator) 

and First Australian Resources (FAR) have a 35-65 

percent interest in three central, offshore blocks—Rufisque (Zone K), Sangomar Deep (Zone Q), and Sangomar (Zone O)—covering 7,490 km2

 over the Senegalese 

portion of the productive Mauritania-Senegal-Guinea 

Bissau Basin.772 FAR’s OOIP estimate ranges from 200 

million bbl to greater than 1 billion bbl potential, in 

part because of parallels its block has to Mexico’s Cantarell super-giant field. In pre-rift time, Senegal was 

considered to be adjacent to Mexico before the African 

and American continents pulled apart.773 The UK’s 

Elenilto operates a 7,920 km2 block in the Southern 
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Senegal Casamance offshore basin in the south, with 

Petrosen as a minority shareholder.774 Elenilto calculates that there are 500-800 million barrels in hydrocarbon content in this block, which is similar to other 

fields elsewhere in West Africa (Mauritania, Sierra 

Leone, Liberia, Cote d’Ivoire, and Ghana).775

JDZ with Guinea-Bissau. 

The UK’s Ophir Energy has a 79.2 percent operated interest in the Profond Block of Senegal’s JDZ with 

Guinea-Bissau.776 Although Ophir’s Kora-1 exploratory well was drilled and abandoned in 2011,777 Profond 

is estimated to contain 400 million barrels of oil.778

Seychelles.

Although international oil companies have explored for oil and gas in the waters around the Seychelles since the 1970s, no commercially viable hydrocarbons had been found as of year-end 2012. 

Nevertheless, the government’s Seychelles Petroleum 

Company (Sepec) has aggressively sought foreign 

investment,779 including contracting for 20,000 km of 

seismic data in 2011, which it expected would “significantly expand . . . [the] interest in the hydrocarbon potential of the Seychelles.”780 Global interest 

in the waters off the coast of the Seychelles has also 

been sparked following recent success in the region, 

including Anadarko’s large gas discoveries off the 

Mozambique coast and BG’s promising gas discoveries in Tanzania.781 In November 2012, the Seychelles 

government delayed a bid round on 30 blocks to give 

itself time to seek advice from the International Monetary Fund on negotiations with potential investors,782
213

including possibly increasing petroleum revenue 

royalties to 10 percent, from 5 percent.783 The government plans to revise its draft petroleum law by May 

2013, after which the government will invite companies to negotiate on a one-on-one basis for exploration 

licenses.784

There are currently two main foreign oil companies 

exploring in the Seychelles: Australia’s WHL Energy 

has a 100 percent interest in 20,476 km2 off the southern coast,785 and the UK’s Afren operates a 75 percent 

interest in approximately 14,319 km2 in Areas A and 

B, which are located in the mainly shallow water in 

the northern half of the Seychelles plateau. (The UK’s 

Avana Petroleum has a non-operator 25 percent interest.) WHL undertook extensive 2D seismic work and 

reprocessed existing seismic dates, rebuilding hydrocarbon basin models with reference to other hydrocarbon rich basins in East Africa in particular.786 The firm 

hired an independent consultant, which announced in 

November 2012 that WHL had a total unrisked mean 

prospective resource of 3.45 billion barrels for the 21 

most highly ranked leads in its portfolio.787 WHL announced in April 2013 that it had signed a letter of 

intent with a top 100 Fortune Global 500 oil and gas 

company to farm into its frontier exploration effort.788

Afren commenced a major 3D seismic program in 

Areas A and B in late 2012,789 and earlier had relinquished its license in Area C in order to focus on these 

first two areas.790 The firm believes that the tectonic 

evolution of the underwater Seychelles Plateau is related to three phases of rifting that isolated the now 

drowned micro-continent from the center of Gondwanaland.791 The Western Seychelles Margin, according 

to Afren, can be reconstructed to a position adjacent 

to Somalia and as a northern extension of Madagascar 
214

prior to drifting from Africa. A second phase of rifting 

occurred when India and Seychelles separated from 

Madagascar.792 Plate reconstructions also show the 

geological closeness of the proven petroleum systems 

in both India and Madagascar.793

Sierra Leone.

The discovery of Ghana’s Jubilee field in 2007 triggered the interest of international oil companies in 

exploring offshore West Africa in an area known as 

the West Africa Transform Margin, which stretches 

1,500 km between two tectonic plates along the coasts 

of eastern Ghana, Cote d’Ivoire, Liberia, and Sierra Leone. A hydrocarbon assessment published by the U.S. 

Geological Survey in 2011 of an area of about 202,700 

km2

 in offshore Guinea, Liberia, and Sierra Leone estimate mean volumes of undiscovered hydrocarbon 

resources in this area to be 3.2 billion barrels of oil, 

23.63 tcf of gas, and 721 million barrels of natural gas 

liquids. Recent discoveries, including oil discoveries drilled by U.S. firm Anadarko Petroleum (Venus 

in Block SL-06 in 2009, Mercury-1 in Block 07B-10 in 

2010, and Jupiter-1 in 2012),794 indicate the likelihood 

of major oilfields being discovered offshore in Sierra 

Leone because they confirmed that the main reservoir 

and source elements in the Jubilee Field in Ghana are 

present in the Sierra Leone/Liberia deepwater basin.795

Exploration remains at an early stage, but prospects 

look good for Sierra Leone to become a new frontier 

for oil and gas.796 Assessments made in Sierra Leone 

suggest high potential and good possibility of large oil 

and gas field size (500-700 million barrels of oil and 4 

tcf of gas).797
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Sierra Leone’s government awarded eight offshore 

oil blocks in July 2012, teaming various bidders together as forced partners for four of the blocks. U.S.-

based Kosmos Energy and Australia’s African Petroleum were awarded Block 4A; South Africa’s Signet 

Petroleum and UK-firms Menexco Petroleum and 

Elinilto received Block 7a; and the U.S. firms Chevron 

(operator, with 55 percent interest) and Noble Energy 

(30 percent), as well as UK firm Odye (15 percent), 

were awarded Blocks 8a and 8b, which will become 

one concession.798

After earlier awards and farm-ins, Block SL-4b-10 

is now operated by Canada’s Talisman (30 percent), 

with other shares owned by Russia’s Lukoil (25 percent), Malaysia’s Petronas (25 percent), and the UK’s 

Protinal (20 percent).799 Block 07B-11 is owned by 

Anadarko, Anglo-Irish Tullow, and Spain’s Repsol.800

Lukoil had announced a $100 million drilling program for its 49 percent stake in another block, SL-5-11, 

which is also co-owned by Nigeria’s Oranto (30 percent) and the U.S. firm PanAtlantic (21 percent).801 Lukoil and Vanco are partners in a number of blocks in 

West Africa’s frontier acreage, including in Ghana.802

Repsol acquired three offshore blocks in 2011, which 

the firm believes “could be a new oil area.”803

Somalia.

Estimates of onshore and offshore reserves in Somalia vary greatly, but run as high as 110 billion barrels 

of oil.804 The country is also known to have significant 

deposits of natural gas.805 Oil seeps were first identified by Italian and British geologists during the colonial era. Exploration activities had focused on northern Somalia, where several American firms including 
216

Amoco, Chevron, ConocoPhillips held concessions, 

but were forced to declare force majeure following the 

collapse of the central government in 1991.806 Independent international E&P companies are presently investing in Puntland and Somaliland despite the legal 

and political uncertainties. Somalia’s federal government, which gained more international credibility following the successes of the African Union Mission in 

Somalia (AMISOM) in beating back the terrorist group 

Al-Shabaab, which had taken control of large swaths 

of south-central Somalia. The federal government has 

stated that it will recognize permits issued prior to 

1991, but has been undecided on whether post-1991 

concessions, including those in Puntland and Somaliland, would be recognized.807 In April 2013, Somalia 

Petroleum Corporation announced that the government intended to sign 30 PSCs by year-end, starting 

with firms that held acreage before the civil war. This 

will be complicated, and resolving the situation may 

take years, not least because several blocks have already been relicensed by Puntland and Somaliland.808

Challenging the central government, in November 

2012, Somaliland’s Minister for Mining, Energy, and 

Water Resources announced an “open door policy” 

for investors in his region.809

Another uncertainty for oil and gas exploration 

in Somalia has been a dispute with Kenya over the 

two countries’ maritime boundary. The government 

of Somalia claims that the awards made by Kenya to 

ENI and Total are illegal because they lie in waters 

claimed by Somalia. Kenya’s position is that the maritime boundary should run due east from the land border, while Somalia says the boundary should extend 

perpendicular to the coastline.810
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Puntland. 

These optimistic estimates of Somalia’s hydrocarbon potential are derived in part from geological analysis suggesting that Puntland’s Dharoor Valley in the 

north and the Nugaal Valley in the south are extensions, respectively, of the Masila and Marib-Shabwa 

Basins of Yemen, which currently produce 400,000 

bpd. The northern part of East Africa was part of the 

much larger Gondwana mega-continent until Puntland was finally separated from the Arabian Peninsula during the opening of the Gulf of Somalia, at which 

point the Dharoor and Nugaal Basins were separated 

from their analogues in Yemen.811

Australia’s Range Resources estimated that the 

northern Puntland province had the potential to produce 5-10 billion barrels of oil.812 These two blocks 

cover an area of over 9.7 million acres. With only three 

wells drilled in the two block areas, this is one of the 

least explored areas in Africa.813 Signs of oil were confirmed in Dharoor in January 2012, when Canada’s 

Horn Petroleum drilled the first well in Somalia in 20 

years in Dharoor,814 adding a second well in June 2012. 

News reports about the two wells have been contradictory, with one source indicating that the two wells 

are thought to contain 300 million barrels of oil each,815

while another indicated that commercial quantities of 

oil had yet to be found.816 Further testing is needed 

to determine best prospects, but Horn estimates that 

the Dharoor Field contains 6 billion barrels of oil,817

and has made commitments to drill at least two more 

exploratory wells by 2015.818 Horn Petroleum’s share 

in its two blocks in Dharoor and Nugaal is 60 percent, with 20 percent each for Range Resources and 

Red Emperor.819 Red Emperor believes that Dharoor 
218

and Nugaal have 19.9 billion barrels of oil in place.820

Range first entered Puntland in 2005 and has an unofficial role as an advisor to the Puntland administration 

on attracting international oil and gas investment.821

The CEO of Canada’s Africa Oil, which has a 45 percent equity interest in Horn Petroleum,822 stated in 

August 2012 that: 

while we were disappointed that we were not able 

to flow oil from the first two exploration wells in our 

Puntland drilling campaign, we remain highly encouraged that all of the critical elements exist for oil 

accumulations, namely a working petroleum system, 

good quality reservoirs and thick seal rocks.823

Somaliland. 

The autonomous region of Somaliland contains 

geological basins similar to both Yemen and Uganda, 

where millions of barrels of oil reserves have been discovered. As with the rest of Somalia, these estimates 

are highly speculative, however, and only a cumulative total of 21 wells had been drilled in Somaliland as 

of the end of 2012. There may also be vast reserves of 

natural gas offshore,824 as appears increasingly to be 

the case for much of the coast of East Africa, running 

from Mozambique, Madagascar, Tanzania, and Kenya. The UK’s Genel Energy was awarded an exploration license for onshore Blocks SL-10-B and SL-13 in 

Somaliland, with a 75 percent interest in both (along 

with 25 percent share partner East Africa Resource 

Group), as well as farmed-in for a 50 percent share in 

the Odewayne PSA, which covers Blocks SL-6, 7, and 

10A (along with 30 percent for Australia’s Jacka Resources and 20 percent for Petrosoma).825 Genel plans 

a 2D seismic campaign for its blocks in 2013, with the 
219

first exploration well in the second half of 2014.826 Genel believes the block could contain one billion barrels 

of prospective resources, with 15 percent probability 

of success.827 The UK’s Ophir has a 75 percent operated interest in Berbera Blocks (SL 9 and SL 12),828 while 

Norway’s DNO International was awarded onshore 

Block SL 18.829

South Africa.

South Africa’s proven oil reserves total a trifling 

15 million barrels,830 but this figure could increase 

dramatically in the coming years. Besides the modest 

and declining reserves offshore Mossel Bay in eastern 

South Africa, the country’s only other current reserves 

are offshore in southern South Africa in the Bredasdorp Basin and in western South Africa, particularly 

in the Orange Basin adjacent to Namibia. 

Offshore exploration in South Africa is intensifying, spurred by: 1) massive gas discoveries to the east 

in Mozambique in 2010, 2) modest discoveries in the 

Bredasdorp Basin to the south as the result of drilling 

since the 1980s, and 3) encouraging results in the Orange Basin in the east, south of Namibia.831 Onshore, 

much of the exploration is in unconventional oil and 

gas in the Karoo Basin in the west near Botswana, and 

in coal-bed methane in the northeast. 

Extending the East Africa Gas Boom.

U.S supermajor ExxonMobil will be the operator 

for exploration in 2.8 million acres of South Africa’s 

east coast, hoping to expand the energy boom along 

Africa’s Indian Ocean flank that was set off by massive 

gas discoveries off Tanzania and immediate neighbor 
220

Mozambique. In December 2012, Exxon acquired a 75 

percent operator interest in exploration rights in the 

Tugela south blocks from the UK’s Impact Oil and 

Gas and acquired the right to buy a 75 percent interest in three other offshore blocks for which Impact 

currently holds technical cooperation permits.832 The 

U.S. giant also signed a technical cooperation agreement with the South African government to study 

oil and gas potential in the deepwater Durban Basin, 

which covers about 12 million acres of seabed.833 Sasol 

holds exploration rights in another large block east of 

the Tugela permit and exploration right areas, up to 

the border with Mozambique.834 Impact has sought 

a license for technical studies in the Transkei Permit 

area offshore East London, which is further west of 

the Tugela blocks. Even further west, in the area offshore of South Africa’s southernmost Cape Agulhas, 

PetroSA operates the small Sabel oil field, and several 

IOCs have technical cooperation permits and exploration rights, including France’s Total, Anadarko, and 

smaller oil and gas companies, or “minnows,” such 

as Impact, Singapore’s Silver Wave Energy, as well as 

South Africa’s PetroSA. 

Offshore Oil, Gas-to-Liquid. 

South Africa’s PetroSA operates the Oribi and Oryx 

fields, located in Block 9 off South Africa’s southern 

coast in the Bredasdorp Basin. The fields are 120 km 

southwest of Mossel Bay, where a gas-to-liquid refinery is located. These two fields currently only produce 

1,800 bpd, with a declining reserve. PetroSA’s Project 

Ikhwezi involves tapping into gas reserves in the F-O 

field, which is 40 km from its current offshore production platform. First gas is scheduled to flow in May 
221

2013, with production lasting 6 years and possibly to 

2025 with development of other nearby gas fields.835

Western Cape Oil & Gas E&P. 

The Orange Basin is believed to hold substantial oil 

and gas reserves, but exploration is in a preliminary 

stage and large-scale commercial production is years 

away, with first gas in 2016.836 Large international oil 

firms Anglo-Dutch Shell and the U.S. firm Anadarko, 

joined in other blocks by the UK’s Cairn India and 

Afren, Australia’s Sunbird and BHP, and South Africa’s PetroSA, Sasol, Thombo, and Sungu Sungu,837 are 

betting that the “geological strata running on land and 

under the sea southward from Uganda and the Great 

Lakes extend to South African territory.”838 In August 

2012, Cairn India, owned by the UK’s Vedenta Group, 

acquired a 60 percent operator share of offshore Block 

1 in the Orange Basin along the maritime border with 

Namibia, with PetroSA holding the remaining 40 percent.839 Sunbird Energy acquired a 76 percent share in 

the 870 bcf Ibhubesti Gas Project in Block 2A offshore, 

with PetroSA holding the remaining 24 percent. “Following the recent launch of PetroSA’s Ikhwesi Project, 

the Ibhubesi Gas Field is now the largest undeveloped 

gas discovery in South Africa.”840 Thombo is the operator for development of Block 2B, which is located in 

the Orange River Basin offshore shallow water area lying between the Ibhubesi gas field and the Namaqualand coast. Other partners include the UK’s Afren (25 

percent share). Thombo started 3D seismic work 2013 

1Q841 and exploration drilling is expected in 2014.842
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Karoo Unconventional Oil and Gas. 

U.S. supermajor Chevron announced in December 

2012 that it would team up with Ireland’s Falcon Oil 

and Gas to seek unconventional exploration opportunities in South Africa’s semi-desert Karoo Basin in 

central and southern South Africa.843 The EIA estimated in 2011 that there were 485 tcf of technically recoverable gas in the Karoo,844 which contains the world’s 

fifth largest shale gas reserves.845 Falcon currently has 

a Technical Cooperation Permit giving it exclusive 

rights to obtain an exploration permit in the Karoo Basin. Chevron’s move came only 3 months after South 

Africa lifted a temporary ban on shale gas exploration, or “fracking.” South Africa had awarded Shell a 

technical cooperation permit in 2009 to determine the 

Karoo’s natural gas potential, and the firm submitted 

exploration license requests for the Western, Eastern, 

and Northern Cape Provinces in 2010,846 but strong 

opposition by environmentalists led the South African 

government to initiate the temporary ban.

Coal-Bed Methane. 

Australia’s Kinetiko has a 49 percent, operator 

share with South Africa’s Badimo Gas in a coal-bed 

methane project in eastern Transvaal, where coal 

mining has occurred for over 100 years. It expects to 

drill 7-8 exploration wells in its northern (56ER) and 

southern (38ER) Amersfoort project license areas by 

June 2013, allowing it to better estimate first gas reserves.847 Kinetiko has a 100 percent share in five other 

concessions, while Badimo has one concession. The 

U.S. consultancy Gustavson Associates calculates P50 

Gas in Place (GIP) resource for Badimo’s Amersfoort 
223

tenements of 1.7 tcf and P50 prospective resources of 

1.12 tcf.848 Sunbird has four coal-bed methane projects 

in eastern South Africa (gas estimates in parentheses): 

Somkele, 200 km northeast of Durban (best estimate 

gas-in-place: 190 bcf), Ermelo, 200 km southeast of Johannesburg (800 bcf), Springbok Flats, 150 km northeast of Pretoria (620 bcf), and Mopane, 420 km northeast of Johannesburg (1.9 tcf). 

The South African government also hopes that 

domestic offshore natural gas and onshore shale gas, 

coal-bed methane, as well as gas imports from bordering neighbors Namibia and Mozambique, will provide an alternative to carbon-intensive coal, particularly for electricity and synthetic fuels.849

Sudan/South Sudan.

After decades of war, Sudan and South Sudan 

signed a peace agreement in 2005, leading after a referendum to the independence of South Sudan in July 

2011. Although now independent, the two countries 

remain interdependent in terms of the oil industry because about 75 percent of oil production originates in 

the south, while the entire pipeline, refining, and export infrastructure is in the north. Oil fields in Blocks 

1, 2, and 4, collectively known as the Greater Nile Oil 

Project, are split between the two countries, since it 

covers an area that straddles the North, South, and 

disputed Abyei region.850 A dispute over pipeline and 

export transit fees lingered post-independence, leading South Sudan to halt exports for several months to 

pressure the North to reach an accord on fees. A new 

peace deal was reached in September 2012, including 

a deal on fees, but implementation has been held up, 

inter alia, by renewed differences over border secu-
224

rity. South Sudan had discussed exporting as much 

as 200,000 bpd via the pipeline through Sudan,851 but 

proposed an interim measure in March 2013 of exporting its crude oil by road via Ethiopia to Djibouti.852

Sudan and South Sudan averaged about 425,000 

bpd production in 2011, a significant decline from 

470,000 in January 2011, mainly due to labor shortages. 

The progressive shutoff in oil exports via Sudan starting January 23, 2012, until at least early 2013 meant 

there was little production in 2012. In order of importance in 2011, Sudan and South Sudan oil exports 

went to China (66 percent), followed by Malaysia (9 

percent), Japan (8 percent), United Arab Emirates 

(5 percent), India (4 percent), Singapore (4 percent), 

and others (4 percent). Sudan and South Sudan had 

reserves as of January 2012 variously estimated to be 

between 4.2 billion barrels (Wood Mackenzie) and 6.7 

billion barrels (BP 2011 Statistical Review). Before the 

split, Sudan held 0.5 percent of global reserves and 

was considered a minor producer with 490,000 bpd in 

2009.853 Most natural gas is flared or re-injected, despite known reserves of 3 tcf.854

To strengthen its own independence, South Sudan—the world’s most oil-dependent state with 98 

percent of revenues coming from crude855—also initiated talks with several neighboring countries about 

alternative options for pipelines to ports in East Africa,856 and sought financing from China. As part of its 

immediate negotiating tactics with the north and to 

ensure future independence from Sudan’s pipeline/

port infrastructure, South Sudan signed nonbinding 

memoranda with Kenya in January 2012 to build a 

port to the Kenyan city of Lamu857 and sought in February 2012 to strike a deal with Ethiopia to build a 

pipeline via Ethiopia to Djibouti’s port.858 The Kenya 
225

option would cost $3 billion and take at least 3 years to 

build. Another option would be a pipeline to Uganda, 

potentially linking up with discoveries there, and further transporting the oil to a port in Kenya.859 Whatever new pipeline option(s) is/are chosen, the author 

believes that China, which up to now has been reticent 

to express its willingness to finance the pipeline out of 

fear of antagonizing the north, will eventually finance 

the new pipeline(s), both to benefit from the construction contracts, and to firm up its relations with (and 

access to oil from) South Sudan. In March 2013, Sudan 

and South Sudan signed an agreement, mediated by 

the African Union, which would allow the resumption 

of at least 350,000 barrels of oil exports from South Sudan.860 Barring political issues or technical difficulties 

that may delay the pace of the ramp up and restart 

at additional fields, EIA expects combined oil output 

in both countries to average 210,000 bpd in 2013 and 

450,000 bpd in 2014.861

Sudan signed a new deal with small Finnish company Fenno Caledonian in 2010 for an 85 percent share 

in Block 10 in the northeast, with Sudapet taking the 

remaining 15 percent. Fenno Caledonian, which also 

has a share in Block 14, believes that Block 10 could 

have oil or gas because Block 8 had gas showings and 

the block is part of the same sedimentary base as all 

other blocks in the southern part of Sudan.862 Khartoum launched bidding in early 2012 for six blocks 

clearly located in Sudan with the hope that new exploration could lead to production to replace the oil lost 

to South Sudan and to maturing fields in the north.863

In November 2012, Sudan’s Petroleum Minister visited Brazil to court oil cooperation, including participation by NOC Petrobras.864 Khartoum also inaugurated the new Hadida Field in South Kordofan State in 
226

December 2012, with initial production of 10,000 bpd 

expected to grow to 60,000 bpd. Sudan at year-end 

2012 was producing at 120,000 bpd.865 However, South 

Kordofan, which borders with South Sudan, has been 

the site of continued instability because of conflicts 

between rival tribal groups centered on the disputed 

town of Abyei that has led to the displacement of tens 

of thousands.866

Following sanctions placed on Sudan, Western oil 

companies left Sudan, allowing foreign companies 

from Asia, such as the China’s CNPC, India’s ONGC, 

and Malaysia’s Petronas, to dominate Sudan and South 

Sudan’s oil sectors through various shares in three 

consortia whose minority shareholder include Sudan 

NOC Sudapet and/or South Sudan NOC Nilepet.867

China’s Sinopec (6 percent) and Egypt/Kuwait’s TriOcean Energy (5 percent) are also minority shareholders in one of the three consortia, Dar Petroleum 

(Petrodar), which is based in South Sudan.868 ONGC 

Videsh’s has two projects in Sudan and two in South 

Sudan.869 France’s Total owns an interest in Block B in 

South Sudan and had been preparing to resume exploration activities870 when the South Sudanese government, exercising its right under new hydrocarbons 

legislation, sought to split the massive concession in 

November 2012 into three parts,871 allowing Total to 

keep one part and offering the other two to ExxonMobil and Kuwait’s NOC Kufpec.872 Total preempted the 

move in June 2013 by bringing the two into its portion 

of the divided block itself.873
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Swaziland.

There are no known hydrocarbons in Swaziland.

Tanzania.

LNG Export Trains Possible.

Like Mozambique, Tanzania has also been the site 

of recent large-scale offshore natural gas discoveries. 

These new discoveries have boosted its natural gas reserves to over 34 tcf.874 While there have not yet been 

any commercial discoveries of oil in Tanzania, IOC 

interest is intense, and there were 16 multinational 

companies conducting petroleum E&P in Tanzania in 

2012 under 23 PSAs.875 The UK’s BG Group, the 60 percent share operator of Blocks 1, 3, and 4, announced 

in December 2012 its seventh consecutive successful well, making the case that its discoveries in the 

Jodari Field in Block 1 could anchor Tanzania’s first 

multi-train LNG development.876 The firm’s 40 percent 

share partner, the UK’s Ophir, has targeted first gas 

in 2018,877 but given the technical, political, and financial challenges of such a mega-project, slippage in this 

date appears likely. Ophir announced in April 2013 

that it had raised its estimate for the Jodari Field to 4.1 

tcf of mean recoverable resources and to 12.6 tcf for 

blocks 1, 3, and 4.878 BG drilled the first successful Cretaceous deepwater discovery in May 2013 on Mzia-2, 

approximately 22 km north of Jodari and also in Block 

1.879 In May 2013, partner Ophir raised its recoverable 

resource estimate for the Mzia field to 4.5 tcf.880

Norway’s Statoil, the operator of offshore Block 2, 

announced five successful wells, including Zafarani, 

over a 13-month period ending March 2013 totaling 
228

an estimated 15-17 tcf in natural gas.881 Statoil has a 

65 percent share in Block 2, with ExxonMobil holding the remaining 35 percent. BG, Ophir, Statoil, and 

ExxonMobil may join forces to build an LNG plant,882

with BG planning to present proposed locations for 

a large LNG terminal to the Tanzanian government 

in the coming months.883 The UK’s Aminex and Solo 

Oil have, respectively, 75 and 25 percent shares in the 

20 percent onshore, 80 percent offshore Rovuma PSA 

in southeast Tanzania, where they have successfully 

drilled two exploratory wells, including Ntoya-1 in 

the Mtwara Block that is estimated to hold 1.17 tcf of 

unrisked gas.884

Following Statoil’s discovery of four more tcf in 

June 2012 in Block 2, Tanzanian Energy and Minerals 

Minister Sospeter Muhongo announced in late June 

that the government planned to introduce new legislation for the gas industry. The Minister stated:

Deepwater offshore oil and gas exploration is a very 

expensive undertaking. It is important to ensure this 

gas and oil exploration momentum continues, and the 

government will give a bigger push for companies to 

proceed.885

Muhongo announced in July 2012 that royalties 

on gas production would rise from the current 12.5 

percent, with the actual increase to be determined in 

conjunction with the new legislation.886 The Minister 

also announced an increase in signing fees and a review of existing contracts—the latter, he later stressed 

in September 2012, would only be carried out to avoid 

mistakes in negotiating future deals.887 Consistent 

with building momentum, Tanzania announced that 

it would soon offer nine new southeast blocks adjacent to the blocks where Anadarko and ENI made 
229

large gas discoveries offshore Mozambique, in depths 

from 2,000 to 2,500 meters, possibly in 2013 4Q.888 Seven more blocks, further off the country’s Indian Ocean 

coast in depths of 3,000 meters, will be auctioned off 

at a later date.889

The UK’s Afren has picked up a 74 percent interest in the Tanga Block from Petrodel Resources; the 

block is onshore and offshore in northeast Tanzania 

and adjacent to Afren’s L17/L18 blocks in southern 

Kenya.890 France’s Maurel et Prom owns a 60 percent 

exploration permit to the onshore Bigwa—Rufiji and 

Mafia Block, where “gas resources [are] to be developed.”891 Australia’s Swala Energy has two onshore 

licenses in the West Rift Valley for which it will carry 

out 2D seismic surveys in 2013 2Q, Kiloa-Kilombero 

in east-central Tanzania and Pangani running parallel 

to its northern border with Kenya.892 In 2011, Australia’s NuEnergy signed joint venture agreements with 

Tancoal and Tanzacoal for exploration for coal-bed 

methane in the two firms’ coal fields in southern Tanzania near the Malawi border. NuEnergy began scout 

exploration drilling during 2012 2H.893

In February 2013, the government announced that 

it would soon issue a license to France’s Total to explore in Lake Tanganyika, on the border with DRC.894

In March 2013, Australia’s Jacka Resources signed a 

PSA with the government for the Ruhuhu Block onshore in southwest Tanzania. The Ruhuhu Basin is 

one of a chain of Karoo geological era basins across 

southern Africa and abuts the northeast shore of Lake 

Malawi (Nyasa).895
230

Monetizing Gas Resources Through Domestic Investment.

The Tanzanian government also promoted the expansion of two major projects to monetize its natural 

gas resources:

1. Songo Songo: Orca currently supplies gas from 

the Songo Songo Field primarily for power generation 

to the Tanzania Electric Supply Company, Songas, 

and 38 industrial customers in the Dar Es Salaam area, 

including PTCC’s cement plant.896 It plans to increase 

its gas production capacity from 113 million cf/d to 

over 200 million cf/d in the coming month. Orca also 

has an ongoing drilling program to double its production from the Songo Songo Field.897

2. Mnazi Bay: 60 percent operator Maurel et Prom 

and 40 percent partner Wentworth of the UK continue 

to develop the Mnazi Bay Concession in the Rovuma 

Basin and drilled a successful well in February 2012.898

Other than supplying one local power plant, however, this resource had been largely stranded since the 

field’s discovery in 2012. Tanzania’s government and 

these partners, however, are changing this. In October 2012, the government secured a $684 million loan 

from China Export-Import Bank to build a new 300 

MW power plant at Mnazi Bay fed by 75 million cf/d 

in natural gas. In November 2012, the government officially started construction of the Mnazi Bay to Dar Es 

Salaam Gas Pipeline Project, with a gas allocation of 

80 million cf/d, with an increase to 200 million cf/d as 

soon as practicable. Finally, Wentworth, with the support of the Tanzanian government, is investigating the 

construction of the Mnazi Bay Petrochemicals Project 

to produce ammonia/urea (e.g., for fertilizer) and 

methanol.899 In June 2012, the Tanzanian government 

concluded a deal with China for a $1.225 billion loan 

from the China Export-Import Bank for the construc-
231

tion of a gas pipeline from Mtwara to Songo Songo, 

where it would connect to another pipeline to Dar Es 

Salaam.900

Border Dispute with Malawi over Hydrocarbons.

As noted previously, Tanzania called on Malawi to 

stop exploring for oil and gas in Lake Malawi (known 

as Lake Nyasa in Tanzania) until a long-standing border dispute between the two countries can be resolved. 

Both nations have agreed to have the African Forum 

mediate their dispute. Malawi claims sovereignty over 

the entire lake, while Tanzania says it is entitled to 50 

percent of it. Malawi awarded two blocks to explore 

the lake in 2011, while Tanzania awarded one block to 

explore its claim in 2012. 

Togo.

Italian major ENI announced in June 2012 that 

geological studies and two offshore exploratory wells 

drilled 17 and 76 km offshore had confirmed the existence of oil in its 100 percent share PSA Blocks 1 

(Oti 1) and 2 (Kara 1) in the Dahomey Basin. ENI plans 

two more wells to determine the quantity and quality 

of oil. The firm’s Togo representative was “optimistic 

[about commercial quantities of oil] to the extent that 

[Togo neighbors] Benin and Ghana have substantial 

oil reserves in the same zone.”901 Four U.S. oil companies had carried out seismic studies and drilling 

off Togo’s coast since the 1960s without finding commercial quantities of oil.902 ENI’s blocks are bordered 

to the west by the analogous Tano Basin in Ghana, 

where major discoveries had been made previously,903

including a find announced by ENI in September 

2012.904
232

Tunisia.

Unlike its oil-producing neighbors Algeria and 

Libya, Tunisia’s upstream industry is modest. Tunisia 

had only 425 million barrels in oil reserves at the end 

of 2011, equivalent to 15 years’ production at the current average of 77,600 barrels of crude per day in 2011. 

The country no longer exports crude oil, as domestic 

consumption has risen in recent years,905 and oil production has declined for most of the last 20 years.906

Despite this modest current production, 57 IOCs 

and local companies conducted exploration and production activities in Tunisia as of 2011 and held 54 

exploration licenses for crude oil and natural gas.907

These large and small IOCs include Spain’s Repsol, 

Australia’s Cooper Energy, Canada’s Chinook Energy and Sonde Resources, Norway’s DNO Resources, 

Sweden’s PA Resources, the UK’s Gulfsands, and 

Vietnam’s PetroVietnam.908

Areas of hydrocarbon importance include the Gulf 

of Gabes and the Ghadames Basin in the southern part 

of the country.909 The UK’s BG Group is the main oil and 

gas producer in Tunisia and accounted for 13 percent 

of production in 2009, ahead of NOC ETAP with 12.3 

percent and Italy’s ENI with 5.6 percent.910 BG’s main 

source of natural gas was the Miskar Field, in which 

it held a 100 percent share, but added the Hasdrubal 

Field in 2009 (50 percent each for BG and ETAP).911 In 

2012, Chinook Energy successfully drilled four horizontal wells in the Sud Ramada field in the Ghadames 

Basin and plans to drill six more wells there in Bir Ben 

Tartar Concession in 2013; the firm also plans to undertake a 3D survey of its offshore Cosmos project in 

2013, with its first well there in 2014.912
233

Uganda.

Anglo-Irish Tullow Oil first discovered hydrocarbons in Uganda in 2006 with then UK partner Heritage Oil & Gas, whose share it subsequently bought 

out.913 In February 2012, Tullow farmed out part of its 

interests to China’s CNOOC and France’s Total, with 

each taking a one-third share in Blocks EA-1, EA-2, 

and the former EA-3, now known as the Kanywataba 

and Kingfisher licenses, and each as operator of one of 

these three blocks.914

In contrast to the situation in Ghana, where Tullow 

has a smooth relationship with the host government, 

the firm and other IOCs have a more contentious relationship with the Ugandan government. The government claimed in 2010 that Heritage owed over $400 

million in taxes because of the sale of its local assets to 

Tullow, but Heritage claims it owes no taxes; the two 

sides are in arbitration in London. In December 2012, 

the Ugandan government reportedly blocked the 

UK’s Ophir Energy from taking over Block 4B when it 

acquired Dominion Petroleum, claiming it was never 

notified of the transaction. Subsequently, Canada’s 

Octant Energy announced in March 2012 that it was 

entering in to a letter of intent to farm-in on Block 4B, 

but it is uncertain whether this sale of a partial interest 

will be consummated. At issue is a tax dispute similar 

to the one between the government and Heritage Oil 

over its sale of its stake to Tullow. In a separate issue, 

Tullow filed a case in December 2012 with the World 

Bank-affiliated International Center for Settlement of 

Investment Disputes challenging the government’s 18 

percent value-added tax on imported machinery and 

supplies.915
234

Yet another contentious issue has been the Uganda government’s desire to build a domestic refinery. 

Uganda President Yoweri Museveni told the Ugandan 

parliament in December 2012 that one of the common 

mistakes of African countries was to lose jobs and oil 

by-products, and increase pipeline transit fees, by exporting crude oil instead of refining it domestically. 

Some third-party observers agreed with Museveni 

that a business case could be made for a large-scale 

refinery in Uganda.916 President Museveni estimated 

that Uganda would lose $40 per barrel by exporting 

crude for refining, in part because crude from Uganda 

is waxy and the 1,300-km pipeline to Mombasa, Kenya would have to be heated, which adds to the export bill.917 For their part, partners Tullow, Total, and 

CNOOC prefer to sell crude on the world market instead of to the refinery and are considering a $5 billion pipeline to the east African coast. In April 2013, 

the government announced that it and three partners 

agreed to “start with the refinery size of 30,000 bpd,” 

which implies that the refinery could be enlarged in 

the future.918 As of May 2013, the government and the 

firms were on the cusp of an agreement that would 

also layout the capacity of the export pipeline, although not include its planned route.919 One wild 

card is the construction of a pipeline from Rwanda, 

through Burundi, to Uganda and the commercial impact that it might have on the potential feasibility of 

the Uganda Kenya pipeline. (See discussion in the section on Rwanda.) 

Tullow’s founder and CEO Aldan Heavey told the 

Ugandan Chamber of Mines & Petroleum in October 

2012 it would cost oil companies $12-14 billion to develop the Lake Albertine region and that it might “take 

20 years to get that money back . . . if you only have 
235

refinery, you have to say how much oil can we sell 

to the refinery?”920 To spur greater competition with 

existing IOCs in Uganda, President Museveni met 

with Russian President Vladimir Putin in Moscow on 

December 11, 2012, to discuss bilateral cooperation 

on energy and mining. Russia’s Lukoil has expressed 

interest in exploration, production, and refining of 

Uganda’s waxy oil, according to the Russian media.921

The new petroleum law passed by parliament in December 2012 set clear guidelines under which the oil 

sector is to operate, but there were also concerns about 

too much discretion given to the Energy Minister (and 

by implication to Uganda’s President) in granting and 

revoking oil licenses, negotiating PSCs, and in promoting or not promoting transparency in the energy 

sector.922

Uganda has exploration blocks that run from the 

Sudan border in the north through Lake Albert on 

the western border with the DRC and south to Lake 

George. Only five blocks have been licensed; 923 the 

government is considering a new licensing round 

with 13 blocks following parliament’s passage of a 

new petroleum law in December 2012.924 Lake Albert 

is part of the Albertine Graben, which stretches from 

the northern end of Lake Albert to the southern end of 

Lake Tanganyika.925

Despite the government’s difficulties in working with IOCs, Uganda remains highly attractive to 

investors because the country’s oil discovery rate is 

an extraordinary 90 percent.926 By another estimate, 

only three of 71 wells drilled in the Lake Albert Graben since 2006 have not encountered hydrocarbons. 

The average cost, including seismic surveys and appraisal drilling to find commercial reserves in Uganda 

has been about $1 per barrel, compared to an average 
236

worldwide cost of $5 to $25 per barrel. Moreover, less 

than 40 percent of the Lake Albert Graben with potential for oil and natural gas has been explored.927 This is 

in only one of five sedimentary basins in Uganda; the 

others have never been explored.928

Estimates of Uganda’s oil reserves have varied 

widely, with Tullow’s website indicating one billion 

barrels and the government of Uganda revising upward reserves to 3.5 billion in September 2012 after 

appraisal activities on two blocks.929 The government 

appointed a panel in July 2012 to work with IOC partners on an overall development plan for the Lake 

Albertine rift basin, which is rich in biodiversity. Oil 

production from the basin is estimated at 200,000 bpd 

36 months after the development plan is approved,930

with further increases in daily production possible. 

First oil production has been repeatedly delayed because of government inaction or disagreements with 

IOCs; 931 Uganda is expected to begin small-scale oil 

production in 2014 or 2015.932 Full-scale commercial 

production is projected to start after 2017 with full 

capacity from 120,000-200,000 bpd unlikely to be 

reached before 2020.933

Western Sahara.

IOCs have sought exploration licenses in Western 

Sahara despite a UN resolution against such deals 

until the issue of the territory’s sovereignty has been 

resolved. Western Sahara, a desert area bordering the 

Atlantic Ocean between Mauritania and Morocco that 

was formerly a colony of Spain, is claimed by Morocco 

and the Polisario, an independence movement based 

in Algeria that has proclaimed the Saharawi Arab 

Democratic Republic (SADR). While information is 
237

sketchy, the SADR granted two petroleum exploration 

licenses to IOCs despite a UN legal notice questioning 

the legality of such exploration.934

Morocco’s NOC, ONHYM, reportedly granted 

France’s Total in 2012 a huge block covering 100,926 

km2

 offshore southern Western Sahara under a reconnaissance contract. However, this leasing of acreage 

is illegal under UN rules.935 For its part, in 2006 the 

SADR granted a subsidiary of the UK’s Wessex Petroleum and two other UK companies a PSC covering the 

Bojador onshore block. In 2007, Wessex agreed with 

Comet Petroleum, the 100 percent holder of the Guetta offshore block, to cross-assignment of interests with 

the Bojador Block group. Wessex also has a 50 percent 

interest of the Imlili offshore block east of the Guelta 

Block, with Tower Resources holding the remaining 

50 percent. (Tower purchased Comet in 2008.) Wessex’s intention is to: 

commence an initial technical evaluation of the blocks 

using the existing dataset, and then, subject to the 

United Nations settlement of the issue of sovereignty 

of the Western Sahara, to find a substantial farm-in 

partner.936

The SADR granted UK’s Ophir Energy a 50 percent operated interest in four blocks with a gross area 

of 74,327 km2.

937 The UK’s Premier Oil purchased a 35 

percent share of the rights of the U.S. firm Fusion Oil 

& Gas in 2003 that had been granted by the SADR.938

Zambia.

Zambia has no proven oil or gas reserves, but the 

presence of hydrocarbons has been confirmed in Chavuma and Zambezi, two districts in the Northwestern 
238

Province.939 Zambian Minister of Mines and Mineral 

Development, Maxwell M. B. Mwale, indicated in 

2010 that: 

Exploration for oil and gas [in Zambia] is being conducted based on the understanding that oil and gas 

has been discovered in countries with . . . the same 

geology. Uganda discovered oil along the East African 

Rift System, which extends to . . . Lake Tanganyika—

Mweru Wantipa Area, Luangwa, Luano–Lukusashi, 

Kafue and Zambezi Valleys. Botswana, on the other 

hand, discovered coal-bed-methane In the Okavango 

Basin, which stretches into the northwestern and western provinces of Zambia.940

In 2009, the Zambia government launched a first 

bid round for 23 blocks and awarded 11 blocks. It 

awarded seven blocks to local Zambian companies 

Majetu (Blocks 3 and 11), Barotse Petroleum (20 and 

21), and, Chat Milling (5, 16, and 19), and four to foreign companies, including the U.S. firm Glint Energy 

(Block 2, next to the Angolan border to the north), the 

UK’s Petrodel Resources (Block 17, next to the Angolan border to the west),941 the UK’s GB Petroleum 

(Block 22, in southwest Zambia), and Canada’s Exile 

Resources (Block 26, in the northeast, close to the Malawi border). (Exile was subsequently purchased by 

Nigeria’s Oando Petroleum.) 

Zambia’s second round of bidding in 2010 did not 

attract any other foreign investors, and the government held off on awarding any new blocks to local 

companies.942 A third round of bidding was held in 

2011, with the U.S. firm Frontier Resources winning 

Block 34, Exile being awarded a second block, and 

a Zambian company winning a third block.943 South 

Africa’s Rapid African Energy was awarded Block 31 
239

in northern Zambia on the borders with the DRC, including Lake Mweru, and Tanzania, including Lake 

Tanganyika.944 The Zambian government plans a 

fourth round of bidding in 2013 and plans to offer 26 

new blocks and six blocks that were offered in earlier 

rounds for which there was no suitable bidder.945

In February 2013, Zambian Mines Minister Yamfwa Mukanga warned that companies holding exploration licenses in Zambia needed to move forward 

with their work or risk losing their licenses.946 One 

company that claims to have been active is Frontier 

Resources, whose Block 34 is 150 km southwest of the 

capital, Lusaka. Frontier believes its block may form 

part of the southwestern extension of the Western Rift 

Valley branch of the East African Rift System,947 has 

been acquiring 2D data near the block shot by an earlier operator, and is reviewing the acquisition of new 

aerogravity/aeromagnetic data.948

Zimbabwe.

Zimbabwe has no proven oil or gas reserves, but 

has potential to become a producer of coal-bed methane gas.949 Minister of Mines and Mining Development Obert Mpofu said in 2011 that Zimbabwe had 

forged a deal with a[n undisclosed] foreign partner to 

explore and develop the “massive oil reserves” that 

the government believes are located in the Zambezi 

Valley. The Minister also stated that “There has been 

a lot of exploration along the Zambezi Valley for oil. 

We have another option to extract oil from coal, but . . .

will only consider that when all other avenues have 

been exhausted.” The Minister acknowledged that 

exploration was still at the initial stage that involves 

the study of structural geology at the reservoir scale 
240

and sedimentary basin analysis.950 Another source 

claimed that Zimbabwe contained the largest reserves 

of methane gas in Africa,951 which could be true given Zimbabwe’s extensive coal beds. Consistent with 

this, Australia’s Sunbird Energy has eight permits for 

exploration in the Kalahari Karoo Basin in northern 

Botswana, approximately 100 km south of the Wankie 

coalfield in Zimbabwe. 

Firms such as Sunbird may be choosing to invest in 

coal beds in neighboring countries such as Botswana, 

South Africa, and Zambia because of the current Zimbabwe government of Robert Mugabe’s hostile attitude toward foreign investment.

ENDNOTES - APPENDIX I

1. “Algeria—Country Analysis Brief,” U.S. Energy Information Agency (EIA), March 8, 2012, lists Libya as ahead of Algeria 

in crude oil production, whereas Mowafa Taib, “The Mineral Industry of Algeria,” U.S. Geological Survey Mineral Yearbook-2010, 

Vol. III, New Cumberland, PA: U.S. Geological Survey, 2010, p. 

2.1, puts Algeria in third place. 

2. Mowafa Taib, “The Mineral Industry of Algeria,” pg. 2.1.

3. “Algeria—Country Analysis Brief,” EIA.

4. Ibid.; “International/Frontier Producing—Algeria,” available from www.anadarko.com/operations.

5. “Key Operating Areas,” available from www.cnoocltd.com/

encnoocltd.

6. “CNPC in Algeria,” available from www.cnpc.com.cn/en/

cnpcworldwide/algeria.

7. See www.gazprom.com/about/production/projects/deposits/

algeria.
241

8. “Algeria Hassi Bir Rekaiz Project,” September 30, 2012, 

available from www.pttep.com/en.

9. “ConocoPhillips to Sell Off Algeria Unit,” Petroleum Africa, 

December 19, 2012.

10. Lahcen Achy, “Algeria Needs More than Hydrocarbon 

Law Amendments,” Al-Hayat, January 22, 2013.

11. “Algeria Assembly Approves Amendments to Energy 

Law,” Reuters, January 21, 2013.

12. “Algeria Plans for Bid Round,” Petroleum Africa, 

November 8, 2012.

13. Achy, “Algeria Needs More than Hydrocarbon Law 

Amendments.” 

14. “Algeria—Output Slides on Joint Ventures,” April 12, 

2012, available from www.africaintelligence.com.

15. Achy, “Algeria Needs More than Hydrocarbon Law 

Amendments.”

16. John Mitchell et al., “Resource Depletion, Dependence, 

and Development: Algeria,” London, UK: Chatham House, November 2008, p. 18.

17. Achy, “Algeria Needs More than Hydrocarbon Law 

Amendments.”

18. “Algeria—Country Analysis Brief,” EIA.

19. Taib, “The Mineral Industry of Algeria,” p. 2.4.

20. “Repsol Makes Illizi Discovery,” Petroleum Africa, 

April 9, 2013.

21. “Repsol in Algeria,” available from www.repsol.com/es_en/

corporacion/conocer-repsol/quienes-somos/presencia-global/argelia.
242

22. “ENI Announces Start-Up of Gas Production from MLE 

Field in Algeria,” February 4, 2013, available from www.eni.com/

en_IT/media/press-releases/press-release.page.

23. “Algeria,” available www.statoil.com/AnnualReport2011/

en/Pages/frontpage.aspx; and “BP in Algeria,” available from www.

bp.com.

24. “Production: Algeria, Gassi El Agreb Redevelopment 

Project,” available from www.hess.com.

25. “El Merk Delivers for Anadarko,” Petroleum Africa, 

May 8, 2013.

26. Ibid.; and “Algeria,” Vietnam National Oil and Gas Group, 

available from english.pvn.vn. Note: PetroVietnam’s website indicates the NOC has an exploration and appraisal contract for Block 

433A and 416B in Algeria.

27. “Algeria—Output Slides on Joint Ventures,” April 12, 

2012, available from www.africaintelligence.com.

28. Paul Williams, “PTTEP, Sonatrach, and CNOOC Discover 

Crude Oil in Algeria,” September 21, 2012, available from www.

offshore-publication.com.

29. “CNPC in Algeria.”

30. “Algeria Sets Aside $80 Billion for Energy Investments,” 

November 5, 2012, available from www.ventures-africa.com.

31. “Doing Business in Algeria: 2012 Commercial Guide for 

U.S. Companies,” Washington, DC: U.S. Department of State, U.S. 

Foreign Commercial Service (USFCS).

32. “Upstream Africa Acreage—Algeria,” Total Factbook 2011, 

Washington, DC: Central Intellience Agency, 2011.

33. “Algeria—Country Analysis Brief,” EIA.

34. “245-South Block (Algeria),” available from www.

rosneft.com.
243

35. “Russian Appraise Algerian Discoveries,” Africa Oil and 

Gas Report, May 2012, p. 16.

36. EAI Short-term Energy Outlook (STEO), as provided by 

USAFRICOM source on April 25, 2013.

37. “Angola Background,” Washington, DC: EIA, January 

8, 2013.

38. “Angola,” available from www.mbendi.com/land/af/an/

p0005.htm.

39. Ibid.; and “Total Leaves Them All in the Dust,” Africa Oil 

and Gas Report, September 3, 2012.

40. “Angola Background,” EIA. 

41. “Angola LNG Up and Running,” Petroleum Africa.

42. “Angola Background,” EIA.

43. “Angola Oil—South West Africa’s Next Crown Jewel,” 

May 16, 2011, available from mergersandacquisitionreviewcom.

blogspot.com/2011/05/angola-west-africas-next-crown-jewel.html.

44. Ibid.

45. “Oil, Gas and Security in Angola,”available from thinksecurityafrica.org/oilgas/oil-and-gas-in-Angola.

46. “Angola Oil—South West Africa’s Next Crown Jewel.”

47. “Another Angola Discovery for ENI,” Petroleum Africa.

48. “Repsol in Angola.” 

49. Oswald Clint and Rob West, “Angola’s Pre-Salt Provinces—the Next Brazil?” Oxford, UK, Oxford Energy Forum, 

November 2012.
244

50. “Research and Markets: Offshore Drilling Industry in 

Middle East and Africa to 2016,” March 25, 2013, available from 

Businesswire.com.

51. “Can Chevron Close the Gap on Total in Angola?” Africa 

Oil & Gas Report, February 25, 2013.

52. “Exploration and Production Operations in Africa—

Angola,” www.total.com.

53. “Can Chevron Close the Gap on Total in Angola?” 

54. “Angola,” available from www.statoil.com/AnnualReport

2011/en/Pages/frontpage.aspx.

55. “Profile: Angola,” available from www.exxonmobil.com. 

56. “BP in Angola,” available from www.bp.com; “Projects and 

Achievements—Girassol,” available from www.total.com.

57. “Angola Oil—South West Africa’s Next Crown Jewel.” 

58. “Mafumeira Sul Gets Go Ahead from Chevron,” Petroleum 

Africa, February 7, 2013.

59. “Angola Fact Sheet,” April 2012, available from 

www.chevron.com.

60. “Angola Oil—South West Africa’s Next Crown Jewel”; 

and “Angola Background,” EIA.

61. “Our Business,” available from www.chinasonangol.com/

our_business.html.

62. “Angola,” available from www.marathonoil.com/Global_

Operations/Angola/Operations.

63. See www.conocophillips.com/zmag/SMID_392_FactSheetOtherInternational.html.
245

64. “Maersk Sees Success with Angola’s Block 16 Well,” 

Petroleum Africa, September 25, 2012.

65. “West Africa,” available from www.cobaltintl.com.

66. “Cobalt Pushes Pre-Salt Program in West Africa,” Petroleum Africa, February 28, 2013.

67. “Cobalt Explores Pre-Salt Potential,” African Energy, May 

2, 2013.

68. “Angola Background,” Washington, DC: U.S. Energy Information Administration, January 8, 2013.

69. “Angola Prepares Onshore Licensing Round,” Petroleum 

Africa, April 5, 2013.

70. “Angola Lines Up Onshore Bid Round,” AfrOil, April 

9, 2013.

71. “Angola/ROC Sign Agreement for Joint Exploration,” 

Petroleum Africa, March 20, 2012.

72. “Accord Paves Way for Chevron Angola/ROC Development,” Petroleum Africa, July 31, 2012.

73. “Angola Background,” EIA.

74. “Benin,” available from www.mbendi.com/land/af/be/p0005.

htm.

75. “Sillinger Looks Forward to Unlocking Benin’s Potential,” 

Petroleum Africa, October 12, 2011.

76. “Benin: des gisements de petrole ont ete decouverts au 

large des cotes du Benin” (“Benin : Oil Deposits Discovered Along 

Coast of Benin”), February 3, 2009, available from westafrica.smetoolkit.org.

77. “Benin.” 
246

78. “Oil, Gas, and Security in Benin,” available from thinksecurityafrica.org/oilgas/oil-and-gas-in-Benin.

79. “Benin Contract Extension,” available from www.sapetro.

com; and John Ankromah, “Seme Field Returns to Production in 

2014,” Africa Oil & Gas Report, March 25, 2013.

80. “Oil, Gas, and Security in Benin,” available from think

securityafrica.org/oilgas/oil-and-gas-in-Benin.

81. Century International Oil & Gas Corporation, “West Africa Offshore Benin,” NYTimes.com, June 2012.

82. See www.poloresources.com/Investments_Signet.htm.

83. “Petrobras Enters Benin,” Petroleum Africa, February 24, 

2011; and see www.petrobras.com. 

84. “Deepwater Blocks 5 & 6 Benin Offshore Farm in Opportunity,” available from www.simco-pet.com.

85. “Oil and Gas Availability in Botswana,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-Botswana.

86. “Sasol Announces Joint Venture Participation with Origin Energy in Coal Bed Methane Exploration,” November 1, 2011, 

available from www.sasol.com; and “Origin Energy Shareholder 

Review 2012,” available from reports.originenergy.com.au/2012/

shareholder/.

87. Josh Lewis, “Duo to Explore Botswana CBM,” November 

2, 2011, available from www.upstreamonline.com.

88. See www.sunbirdenergy.com.au/Botswana/kasane-project.

html.

89. Iain Esau, “Tlou in Botswana CBM Push,” February 

28, 2013.

90. “Botswana CBM,” available from www.magnumgpl.com.
247

91. “Upstream update : Zambia, Malawi, and Botswana,” 

African Energy, May 16, 2013.

92. “Botswana Petroleum,” available from www.magnumgpl.

com.

93. Desire Nimubona, “Le Burundi sur le point de produire 

du petrole” (“Burundi About to Produce Oil”), September 26, 

2012, available from www.isanganiro.org.

94. “Burundi,” available from www.poloresources.com/

Investments_Signet.htm.

95. Nimubona, “Le Burundi sur le point de produire du 

petrole” (“Burundi About to Produce Oil”).

96. “Burundi: Lake Tanganyika Exploration Eyed,” Oil & Gas 

Journal, February 3, 2011.

97. “East Africa Rift System: Lake Tanganyika, Burundi 

Blocks B and D Farm-in Opportunity,” Surestream Petroleum, 

April 30, 2012.

98. “Oil, Gas and Security in Cameroon,” available from 

www.thinksecurityafrica.org/oilgas/oil-and-gas-in-Cameroon; and 

“Cameroon Oil and Gas Profile,” available from www.abarrelfull.

wikidot.com.

99. “Cameroon Oil and Gas Exploration in 2011 and 2012,” 

June 20, 2011, available from mergersandacquisitionreviewcom.

blogspot.com/2011/06/cameroon-oil-and-gas-exploration-in.html.

100. Jean Jacques Nguimbous-Kouoh et al., “Structural Interpretation of the Mamfe Sedimentary Basin of Southwestern Cameroon along the Manyu River Using Audiomagnetotellurics Survey,” ISRN Geophysics, Vol. 2012, Article ID 413042, 2012.

101. “Cameroon,” available from www.mbendi.com/land/af/ca/

p0005.htm.

102. “Cameroon,” available from www.bowleven.com.
248

103. “Oil, Gas and Security in Cameroon,” available from 

www.thinksecurityafrica.org/oilgas/oil-and-gas-in-Cameroon.

104. “Regions Petroliferes en Afrique” (“Petroleum Regions 

in Africa”), available from fr.wikipedia.org.

105. “Cameroon Hosting Bid Round,” Petroleum Africa, March 

8, 2013.

106. “Cameroon,” available from www.perenco.com/operations/

Africa/Cameroon.

107. “Cameroun: de nouvelles reserves de petrole et gaz 

naturel,” (Cameroon: New Oil and Gas Reserves), October 16, 

2012, available from www.legriot.info; “Cameroon Plans for Crude 

Boost,” Petroleum Africa, January 26, 2012.

108. “Cameroon,” available from www.perenco.com/operations/

Africa/Cameroon.

109. “Cameroon—License Areas,” available from www.

addaxpetroleum.com/operations/cameroon.

110. “Sinopec Enters Cameroon,” Petroleum Africa, November 

8, 2011.

111. “Bowleven Sees Even More Pay at Sapele,” Petroleum 

Africa, January 11, 2011.

112. “Sapele-3 Hits for Bowleven in Cameroon,” Petroleum Africa, October 17, 2011; “Bowleven Nears TD Offshore Cameroon,” 

Petroleum Africa, February 1, 2013; “Bowleven has Intra Isongo 

Discovery Offshore Cameroon,” Oil & Gas Journal, February 2013.

113. “Cameroon: Oil and Gas Exploration in 2011 and 2012,” 

June 20, 2011, available from mergersandacquisitionreviewcom.

blogspot.com/2011/06/cameroon-oil-and-gas-exploration-in.html.

114. “Cameroon,” available from www.bowleven.com.

115. “Bowleven va investir $900 millions au Cameroun” 

(“Bowleven Will Invest $900 Million in Cameroon”), March 30, 

2012, available from AfricaTime.com.
249

116. “Cameroon,” available from www.afexglobal.com/

operations/cameroon.

117. “Cameroon,” Vietnam National Oil and Gas Group, 

available from english.pvn.vn. 

118. Toyin Akinosho, “Kosmos Throws $75 Million in the 

Hole,” Africa Oil & Gas Report, May 21, 2013.

119. “Cameroon,” available from www.kosmosenergy.com/

operations-cameroon.

120. “Cameroon: Kosmos Energy Signs PSC for Fako Block, 

Onshore Cameroon,” January 15, 2012, available from www.

energy-pedia.com/news/cameroon/new-148724.

121. “Republic of the Congo,” available from www.murphyoilcorp.com.

122. Tess Stynes, “Murphy Oil Offshore Congo Well Proves 

Unsuccessful,” The Wall Street Journal, November 21, 2012.

123. “Cameroon: Ntem,” available from www.sterlingenergyuk.com.

124. “West Africa,” available from www.nobleenergyinc.com.

125. “Cameroon: Oil and Gas Exploration in 2011 and 2012,” 

June 20, 2011, available from mergersandacquisitionreviewcom.

blogspot.com/2011/06/cameroon-oil-and-gas-exploration-in.html.

126. “NBL Noble Energy,” pdf presentation at Noble Energy 

Analyst Conference, December 6, 2012.

127. “No Trema Oil for Noble Energy (Cameroon),” October 

18, 2012, available from www.offshoreenergytoday.com.

128. “Africa—Cameroon,” available from www.danapetroleum.com/Our-businesses/Africa/Overview.

129. “Cameroon—Expanding into Cameroon,” available from 

www.madisonpetro.com.
250

130. “Nigeria/Cameroon to Jointly Explore Bakassi Region,” 

Petroleum Africa, March 14, 2011.

131. “Cameroun: La Chine s’investit dans le petrole et le 

gaz naturel” (“Cameroon: China Invests in Oil and Natural 

Gas”), April 5, 2009, available from accypresse.over-blog.com/

article-29907951.html.

132. Emmanuel Tumanjong, “Floods Halt Exploration of Chinese Company in N Cameroon,” January 11, 2013, available from 

www.rigzone.com.

133. “Cameroon,” available from www.bowleven.com.

134. Philippe Nsoa, “Cameroun: Le gaz naturel cherche sa 

voie” (“Cameroon: Natural Gas Finds its Path”), September 8, 

2011, available from www.ajafe.net.

135. “Cameroun LNG,” available from www.gdfsuez.com/

wp-content/uploads/2012/05/cameroun-uk.pdf.

136. Achille Mbog Pibasso, “D’importantes reserves de petrole et de gaz” (“Important Oil and Gas Reserves”), Les Afriques, 

March 7-13, 2013.

137. “Cameroon,” available from www.perenco.com/operations/

Africa/Cameroon.

138. “VOG Steps Toward Commercialization at Logbaba,” 

Petroleum Africa, June 14, 2011.

139. “Cameroon: Recent History,” available from www.

victoriaoilandgas.com.

140. “Country Commercial Guide—Cameroon,” Washington, 

DC: Department of State, USFCS.

141. “Brazil’s Petrobras to Support Cape Verde in Ultra-deepwater Oil and Gas Prospecting,” July 5, 2010.
251

142. “Cameroon and Cape Verde—2010 [Advance Release]” 

U.S. Geological Survey Minerals Yearbook 2010, New Cumberland, 

PA: U.S. Geological Survey, 2010.

143. “Sonagol Wants Refinery and Oil and Gas Wells in Cape 

Verde,” June 5, 2006, available from www.macauhub.com.

144. “Petrole: Les Chinois reprennent la recherche de petrole 

en Centrafrique” (“Oil : The Chinese Restart Oil Exploration in 

the Central African Republic”), February 1, 2012, available from 

commodesk.com.

145. David-Christian Vonto, “Réflexion Sur La Possibilité 

d’Implantation d’une Raffinerie en RCA” (“Reflections on the 

Building of a Refinery in the CAR”), 2006, available from www.

sozowala.com.

146. “Central African Republic,” World Factbook, available 

from www.cia.gov.

147. “Ousted Central African Republic leader Bozize seeks 

exile in W. African Nation of Benin,” The Washington Post, March 

29, 2013.

148. “Self-Proclaimed President Michel Djotodia Elected Interim Central African Republic President,” April 13, 2013, available from www.breakingnews.com.

149. See www.mbendi.com, quoting 2012 BP Statistical Energy 

Survey.

150. “Chad Oil History,” Geointelligence Network, available 

from www.geosint.com. 

151. See “Chad,” www.mbendi.com/land/af/ch/p0005.htm.

152. “Oil, Gas, and Security in Chad,” March 5, 2013, available 

from thinksecurityafrica.org/countries/security-in-chad/.

153. “Chapter 1: Doing Business in Chad,” 2012 Country Commercial Guide for Chad, Washington, DC: Department of State, U.S. 

Foreign Commercial Service, 2012.
252

154. “Chad Fact Sheet,” April 2012, available from www.

chevron.com.

155. “Profile: Chad/Cameroon—Doba Basin,” available from 

www.exxonmobil.com.

156. “The Mineral Industry of Chad,” Chad—2011 [Advance 

Release], U.S. Geological Survey Minerals Yearbook 2011, p. 9.1.

157. “Du petrole chinois pour l’oleoduc Tchad-Cameroun” 

(“Chinese Oil for the Chad-Cameroon Pipeline”), Agence Ecofin, 

February 16, 2012.

158. “Griffiths to Connect Production to Chad/Cameroon 

Pipeline,” Petroleum Africa, January 31, 2013.

159. “Griffiths Energy Provides Development and Exploration Update,” Griffiths Energy International press release, January 28, 2013.

160. “Griffiths Progresses Work in Chad,” Petroleum Africa, 

March 26, 2013.

161. “Glencore Picks Up Stakes in Griffiths’ Chad Blocks,” 

Petroleum Africa, September 26, 2012.

162. “Griffiths Energy revives IPO plans,” African Energy, 

May 16, 2013.

163. Carrie Tait and Jacquie MacNish, “Police Seize Griffiths 

Shares After Search of Law Office,” The Globe and Mail, February 

22, 2103.

164. “ERHC Signs EEA with Chad,” Petroleum Africa, July 

19, 2012.

165. “ERHC’s Oil and Gas Exploration Interests in Chad,” 

available from www.erhc.com.

166. “Simba Energy in Chad,” available from www.

simbaenergy.ca/projects/chad.aspx.
253

167. “Tchad: Simba Energy dans l’aventure petroliere” 

(“Chad: Simba Energy in Petroleum Adventure”), Journal du 

Tchad, October 22, 2012.

168. “Simba Takes on Three Chadian Blocks,” Petroleum 

Africa, September 25, 2012.

169. As of March 2013, Taiwan authorities maintained diplomatic relations with only four countries in Africa: Burkina Faso, 

the Gambia, Swaziland, and São Tomé and Principe.

170. “Upstream Operations,” available from www.cpc.com.tw.

171. “CNPC in Chad,” available from www.cnpc.com/cn/en/

cnpcworldwide/chad.

172. “The Mineral Industry of Chad,” Chad—2011 [Advance 

Release], U.S. Geological Survey Minerals Yearbook 2011, p. 9.2.

173. “China, Chad Re-Establish Diplomatic Relations, Upsetting Taiwan,” Voice of America, October 31, 2009.

174. George Obulutsa, “Comoros Awards First Oil Exploration License,” Reuters, March 28, 2012; see www.reuters.com/

article/2012/03/28/ozabs-comoros-explorationidAFJOE82R02X20120328; and www.theeastafrican.co.ke/business/

Kenyan+company+wins+Comoros+oil+exploration+

dal+/-/2560/1386360/-/o1gm0r/-/index.html. 

175. “Comores: Elaboration de la legislation petroliere” (“Comores: Elaboration of Oil Law”), September 21, 2012, available 

from www.comores-actualites.com.

176. “International Arbitration Launched Against Comoros 

Government,” Petroleum Africa, November 27, 2012.

177. “Comoros Comments on E&P Agreement,” Petroleum Africa, October 12, 2012.

178. “Cove Energy Directors Look to Replicate Success in Mozambique,” Reuters, March 10, 2013.

179. “Former Cove Execs Form New Company,” Petroleum 

Africa, March 12, 2013.
254

180. Comores/Prospection petroliere: marcher comme sur 

des oeufs” (“Comoros: Oil Exploration Like Walking on Eggs”), 

October 17, 2012, available from www.comores-actualites.com.

181. “Du Protocole avec GTX a la legislation sur le petrole” 

(“From the GTX Agreement to Oil Legislation”), October 17, 2012, 

available from www.comores-actualites.com.

182. “Core Assets—Comoros,” available from www.

avanapetroleum.com/islands.

183. “Congo,” available from www.mbendi.com/land/af/co/

p0005.htm.

184. The figure for the United States has likely fallen since 

2010, however, because the recent rapid increase in U.S. domestic 

shale oil production has displaced imports.

185. “Upstream Africa Acreage,” Total Factbook 2011.

186. “ROC’s Moho Bilondo Nord Requires Big Investment,” 

Petroleum Africa, July 26, 2011.

187. “ROC’s Moho Projects Get Greenlight,” Petroleum Africa, 

March 25, 2013.

188. See total.com/fr/energies-savoir-faire/petrole-gaz/explorationproduction.

189. See also figures for Republic of Congo in “Exploration & Production—Activities in the World,” available from 

www.eni.com.

190. “Republic of the Congo,” available from www.

murphyoilcorp.com/Global-Operations/Atlantic-Margin/#!republic-ofcongo.

191. “Congo (Rep): ExxonMobil farming out Mer Tres Profonde Sud Block, Offshore Republic of Congo,” August 4, 2010, 

available from www.energy-pedia.com.
255

192. “Congo,” available from www.perenco.com/operations/

africa/congo.html.

193. “Congo (Brazzaville),” available from www.afren.com/

operations/congo_brazzaville/.

194. “Congo (Brazzaville),” available from www.maurelet

prom.fr.

195. “Congo,” available from www.socointernational.co.uk/

congo.

196. “Regions Petroliferes en Afrique” (“Petroleum Regions 

in Africa”), available from fr.wikipedia.org.

197. “Congo,” Vietnam National Oil and Gas Group, available from english.pvn.vn. Note: PetroVietnam’s website indicates 

the NOC has the marine XI Block contract.

198. “Other Regions in Africa,” available from www.cnoocltd.

com; “Republic of Congo (Brazzaville),” available from www.

paresources.se; “Svenska Petroleum Exploration Announces the 

Ivory Coast and Republic of Congo Exploration Farm-Ins,” company press release, May 25, 2009; “Congo (Brazzaville),” available 

from www.tullowoil.com; “Upstream Congo,” available from www.

vitol.com/vitol-in-west-africa.html.

199. “CNOOC Congo Hires Drillship ‘Jasper Explorer’,” January 24, 2013, available from www.worldmaritimenews.com; and Ed 

Reed, “China Lines Up Role in Africa’s Rise,” AfrOil, April 2, 2103.

200. “Congo (Brazzaville) Country Analysis Brief,” EIA, 

December 14, 2011.

201. “ENI to Start Congo Pilot Oil Sands Project in 2012,” 

Reuters, October 6, 2011.

202. “Sustainability—The Tar Sands Project,” available from 

www.eni.com/en_IT/world-eni/index.shtml?selectCountry.

203. “Congo (Brazzaville) Country Analysis Brief,” EIA.
256

204. “Access to Energy and Gas Flaring Projects,” available 

from www.eni.com/en_IT/world-eni/index.shtml?selectCountry.

205. “Central African Republic, Cote d’Ivoire, and Togo,” 

U.S. Geological Survey Minerals Yearbook—2010 [Advance 

Release], p. 8.4.

206. “Oil, Gas and Security in Cote d’Ivoire,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-ivory-coast/; and “Oil 

and Petroleum,” (Cote d’Ivoire), available from en.wikipedi.org/

wiki/Energy_in_Cote_d’Ivoire.

207. “Canadian Natural Resources—Baobab,” available from 

www.cnrl.com; and “Cote d’Ivoire—Oil and Gas Discoveries and 

Status of Exploration Activity in 2011 and 2012,” available from 

mergersandacquisitionreviewcom.blogspot.com/2011/05/cote-divoireoil-and-gas-discoveries.html.

208. “Afren PLC : Operations : Cote d’Ivoire,” Blocks CI-01 

and CI-11, available from www.afren.com. 

209. “Svenska Petroleum Exploration Wildcat Finds Gas offshore Cote d’Ivoire,” press release, Svenska, September 28, 2010.

210. “Vanco Hits Light Oil off Cote d’Ivoire,” Petroleum Africa, 

December 8, 2011.

211. “Lukoil Eyes New Ghanaian Drilling,” AfrOil, April 

2, 2013.

212. “Cote d’Ivoire: Lukoil Sign Deal to Seek Oil Offshore Ivory Coast,” October 2, 2012, available from www.energy-pedia.com.

213. “Lukoil Plans Cote d’Ivoire Spend,” Petroleum Africa, 

February 27, 2013.

214. “Paon-1X Exploration Well Discovers Oil in Cote 

d’Ivoire,” news release, Tullowoil.com, June 7, 2012.

215. “Cote d’Ivoire—CI-202,” available from www.

rialtoenergy.com/. and “Rialto Energy is Certain of 40 million 

‘Scuf’,” Africa Oil and Gas Report, September 4, 2012.
257

216. “Ivoire 1X Boosts the West African Transform Margin,” 

Oil & Gas Report, May 2, 2013.

217. Note: Yam’s Petroleum is owned by Lebanese-Ivorian 

architect Pierre Fakhoury, who reportedly was given five exploration blocks as payment for his work on state infrastructure 

projects—raising questions about the transparency of how the 

government awards blocks, at least to domestic investors. “Cote 

d’Ivoire: Oil Discovery for Total,” African Energy, May 2, 2012.

218. “Cote d’Ivoire: Total Acquires an Interest in CI-100 

Deepwater Exploration License,” October 22, 2010, available from 

www.total.com.

219. “Ghana-Cote d’Ivoire: New Find, Old Maritime Dispute,” OilPrice.com, May 10, 2013.

220. “Total Acquires Interests in Three New Ultra-Deepwater 

Exploration Licenses,” February 17, 2012, available from www.

total.com.

221. “Cote d’Ivoire,” available from www.africanpetroleum.

com.au.

222. “Our Operations in Cote d’Ivoire,” available from www.

genelenergy.com.

223. “DRC,” available from www.mbendi.com/land/af/zr/p0005.

htm.

224. “Oil, Gas, and Security in the DRC,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-the-democratic-republicof-congo/.

225. “Operations—DR Congo,” available from www.

heritageoilplc.com/.

226. “News over Ownership of Congolese Oil Blocks Raises Further Corruption Concerns,” June 29, 2012, available from 

www.global witness.org.

227. “Total Farms-in to DRC’s Block III,” Petroleum Africa, 

March 4, 2011; “Democratic Republic of the Congo,” Total Factbook 
258

2011; “Democratic Republic of the Congo (DRC),” available from 

www.sacoilholdings.com/operations/drc.

228. “PetroAfrican Resources Presents its Site Survey Report 

of Block 4 in the Albert Graben Rift System, Democratic Republic 

of the Congo,” available from www.petroafricanresources.com.

229. “DRC,” available from www.socointernational.co.uk/drc.

230. See en.wikipedia.org/wiki/SOCO_International.

231. “DR Congo - EC launches environmental study on Albertine Rift,” African Energy, May 16, 2013.

232 . “DRC to Adopt New Oil Law,” Petroleum Africa, 

February 1, 2013.

233. “Alberta Oilsands Heads to DRC,” Petroleum Africa.

234. “ROC and DRC Programs Updated,” Petroleum Africa, 

November 2, 2011.

235. Eduard Gismatllin, “Soco to Expand Vietnam Field Output 27%, Allowing Dividend,” Bloomberg, March 11, 2013.

236. “Lotshi Block,” available from www.energulf.com/assets/

democratic-republic-of-congo/.

237. “EnerGulf Prepares for DRC Drilling Program,” Petroleum Africa, April 6, 2011.

238. “Drilling in Lotshi in 2013—EnerGulf Resources,” available from www.stockhouse.com/bullboards.

239. “DRC: Lotshi Resource Report In,” Petroleum Africa, May 

12, 2011.

240. “Inpex Pick-up DRC’s Ngani Block,” Petroleum Africa, 

August 26, 2010; “Offshore D.R. Congo Block,” available from 

www.inpex.co.jp/english/business/africa.html.

241. “Resolution of DRC/Angola Dispute on the Way,” Petroleum Africa, September 26, 2012.
259

242. “DRC Negotiates with IOCs to Boost Output,” Petroleum 

Africa, July 21, 2011.

243. “Le petrole et le gaz de RDC interessent Chevron et 

Petrobras” (“DRC Oil and Gas Interest Chevron and Petrobras”), 

Agence Ecofin, July 25, 2011.

244. “Djibouti,” available from www.oysteroil.com.

245. “Oyster Oil Secures Djibouti Acreage,” Petroleum Africa, 

September 20, 2011.

246. “Oyster Awarded Exploration Blocks Off Djibouti,” September 20, 2011, available from somalilandpress.com.

247. “Promising Results in Preliminary Oil and Gas Search in 

Djibouti,” July 20, 2012, available from www.sabahionline.com.

248. Another source indicated that average daily oil production in 2011 was somewhat higher: 735,000 bpd. See www.mbendi.

com/land/af/eg/p0005.htm quoting 2012 BP figures. 

249. “Egypt—Country Analysis Brief,” Washington, DC: U.S. 

Energy Information Administration, July 2012.

250. “Egypt Knocks Out 17 discoveries in Q1,” Petroleum 

Africa, May 7, 2013.

251. “Egypt—Country Analysis Brief,” EIA.

252. “Egypt—2010” [Advance Release], U.S. Geological Survey 

Minerals Yearbook—2010, New Cumberland, PA: U.S. Geological 

Survey, p. 13.5.

253. “Egypt—Country Analysis Brief,” EIA.

254. “Egypt—2010” [Advance Release], U.S. Geological Survey 

Minerals Yearbook—2010, p. 13.5.

255. “Repsol in Egypt,” available from www.repsol.com/es_en/

corporacion/conocer-repsol/quienes-somos/presencia-global/egipto.aspx.
260

256. “Egypt—Country Analysis Brief,” EIA.

257. “Egypt—Country Commercial Guide—2012,” U.S. 

Foreign Commercial Service.

258. Ibid. 

259. “EGAS Announces Block Winners,” Petroleum Africa, 

April 18, 2013.

260. “Egypt to Ask for Bigger Production Share,” Petroleum 

Africa, May 1, 2013.

261. “Apache plans 270 wells in Egypt,” March 5, 2013, available from www.upi.com.

262. “Apache has Big Drilling Plans for Egypt,” Petroleum 

Africa, March 14, 2013.

263. “Egypt,” available from www.apachecorp.com/Operations/

Egypt/index.aspx.

264. “Apache Hits Triple in the Western Desert,” Petroleum 

Africa, May 8, 2013.

265. “JVs/PSCs/Alliances,” available from www.oil-india.

266. “BP in Egypt,” available from www.bp.com.

267. “Egypt—2010 [Advance Release], U.S. Geological Survey 

Minerals Yearbook—2010, p. 13.6.

268. “BP in Egypt,” available from www.bp.com.

269. “ENI: New Oil Discovery In Western Desert of Egypt,” 

ENI press release, February 6, 2013.

270. “Egypt,” available from www.bg-group.com.

271. “Royal Dutch Shell Takes Final Investment Decision on 

Alam El Shawish West Gas Development Project,” press release, 

January 22, 2012, available from www.shell.com.
261

272. “Dana Grows Fatter in Egypt,” Africa Oil & Gas Report, 

March 14, 2013.

273. See en.wikipedia.org/wiki/Energy_in_Egypt.

274. “Equatorial Guinea,” available from www.mbendi.com/

land/af/eq/p0005.htm; “Equatorial Guinea,” Washington, DC: U.S. 

Energy Information Administration, available from www.eia.gov/

countries/country-data. 

275. “Oil, Gas and Security in Equatorial Guinea,” available 

from thinksecurityafrica.org/oilgas/oil-and-gas-in-equatorial-guinea/.

276. “ExxonMobil Starts Production Offshore Equatorial 

Guinea,” August 5, 2003, available from www.gasandoil.com/news/

africa/5a35ec3d5c4dc0fd3cc04b29d3ab79c1.

277. Philip Mobbs, “The Mineral Industry of Equatorial Guinea,” Equatorial Guinea—2011 [Advance Release], U.S. Geological 

Survey Minerals Handbook—2011, p. 15.1.

278. “Equatorial Guinea,” available from www.tullowoil.com.

279. “Production: Equatorial Guinea, Okume Complex and 

Ceiba Field,” available from www.hess.com.

280 . Mobbs, “The Mineral Industry of Equatorial Guinea,”

 p. 15.1.

281. “Country Analysis Briefs—Equatorial Guinea,” EIA, 

February 28, 2012.

282. “Equatorial Guinea,” available from www.mbendi.com/

land/af/eq/p0005.htm; and “Country Analysis Briefs—Equatorial 

Guinea,” EIA, February 28, 2012.

283. “Country Analysis Briefs—Equatorial Guinea,” EIA, 

February 28, 2012.

284. “Equatorial Guinea,” available from www.mbendi.com/

land/af/eq/p0005.htm;
262

285. “Ophir Energy Plc - Equatorial Guinea - Fortuna West-1 

Update,” Ophir press release, September 17, 2012.

286. “Equatorial Guinea—Drilling to Date Has Derisked 1.4 

TCF,” pdf file from the Ophir Energy PLC website, March 2013, 

available from www.ophir-energy.com.

287. A recent discovery made in May 2013 was at the Carla 

South (I-7) exploration well in Block I. See “Equa G’s Carla South 

Exploration Well Finds Oil,” Petroleum Africa, May 3, 2013.

288. Mobbs, “The Mineral Industry of Equatorial Guinea,” 

p. 15.1.

289. “Noble Energy Flows Aseng, Makes New Discovery,” Petroleum Africa, November 16, 2011; “West Africa,” available from 

www.nobleenergyinc.com/Operations/International/West-Africa-140.

html; and Rodney Cook, NBL Noble Energy pdf presentation, 

Noble Energy Analyst Conference, December 6, 2012.

290. “E&P,” available from www.glencore.com. Another 

foreign partner is Sweden’s PA Resources, with maximum 

5.7 percent share. See “Equatorial Guinea,” available from 

www.paresources.se.

291. “Equatorial Guinea,” available from www.afexglobal.com/

operations/equatorial-guinea.

292. “Train 2 Integrated Project Execution of Principles,” Ministry of Mines, Industry, and Energy, press release, January 17, 

2012, available from www.equatorialoil.com.

293. “Country Analysis Briefs—Equatorial Guinea,” EIA, 

February 28, 2012.

294. “Signature of Production Sharing Contract for Block 

A-12, Offshore Bioko, Equatorial Guinea, June 18, 2012, available 

from www.equatorialoil.com.

295. “Equatorial Guinea,” available from www.marathonoil.

com.
263

296. “Repsol in Equatorial Guinea,” available from www.

repsol.com/es_en/corporacion/conocer-repsol/repsol-en-el-mundo/

guinea-ecuatorial.aspx.

297. “TOGY Talks to Tony Renton,” June 20, 2012, available 

from theoilandgasyear.com; and “Equatorial Guinea,” available 

from www.paresources.se.

298. “Projects—Equatorial Guinea,” available from www.

panatlanticexploration.com.

299. “CNPC in Equatorial Guinea,” available from www.

chinaoil.cnpc.com.cn; and Mario Esteban, “The Chinese Amigo: Implications for the Development of Equatorial Guinea,” The China 

Quarterly, Vol. 199l, September 2009, p. 671.

300. Neil Ford, “Asian Companies Target Africa’s Oil and 

Gas,” New African, December 2006, p. 78; “Other Regions in Africa,” available from www.cnoocltd.com (website indicates Equatorial Guinea assets, but does not provide detail); and Mobbs, “The 

Mineral Industry of Equatorial Guinea,” p. 15.1.

301. “Equatorial Guinea Looks to China for Refinery,” Petroleum Africa, July 24, 2012.

302. “Brenham Signs PSC in Equa G,” Petroleum Africa, 

December 24, 2012.

303. “EG New Production Sharing Contracts—A Who’s (Not) 

Who List,” available from transparencyafrica.com.

304. “Murphy Optimistic on Equa Q,” Petroleum Africa, 

November 1, 2012.

305. “Equa G Aims for Onshore Exploration,” Petroleum 

Africa, November 9, 2011.

306. “Equatorial Guinea,” available from www.mbendi.com/

land/af/eq/p0005.htm.

307. See United Nations Security Council Resolution 2023, 

December 4, 2011, for details. Also see “Eritrea: UN Security 

Council Toughens Sanctions,” BBC News, December 5, 2011.
264

308. “Last Stops on the East Africa Oil and Gas Frontier: 

Eritrea, Ethiopia,” March 3, 2012, available from oilprice.com.

309. “Eritrea: Defba Oil Share Company Signs Oil Exploration 

Agreements,” October 6, 2008, available from www.energy-pedia.

com; and “Eritrean—Hidden Oil and Gas Exploration,” available 

from www.eritrea-chat.com.

310. “Eritrea has Petroleum Oil and Gas,” Madote News, 

October 23, 2010; and “Eritrean—Hidden Oil and Gas Exploration,” available from www.eritrea-chat.com.

311. “Eritrean—Hidden Oil and Gas Exploration,” available 

from www.eritrea-chat.com.

312. “Does Eritrea have Petroleum Oil?” Tsfa News, March 

5, 2013.

313. “Eritrea,” available from www.mbendi.com/land/af/er/

p0005.htm.

314. “Bid Names Tried to Make Their Mark in Play,” March 

26, 2010, available from www.upstreamonline.com.

315. “Eritrean—Hidden Oil and Gas Exploration,” available 

from www.eritrea-chat.com.

316. Angelia Sanders et al., “Emerging Energy Resources in 

East Africa,” Norfolk, VA: Civil-Military Fusion Center Mediterranean Basis Team, September 2012, p. 2.

317. “Lundin Petroleum—History in Ethiopia,” October 13, 

2011, available from www.lundin-petroleum.com. Africa Oil currently has a 30 percent interest in Blocks 7 and 8 in Ogaden. See 

“Operations Ethiopia,” available from www.africaoilcorp.com.

318. “Chinese Firm Picks Up Petronas’ Ethiopian Assets,” Petroleum Africa, August 17, 2011.

319. “Looting Ogaden: Ethiopia’s Exploitation of Ogaden’s 

Resources, Land and People,” Resolve Ogaden Coalition, August 

6, 2011, available from www.mathaba.net.
265

320. “Southwest Energy to Explore for Oil and Gas in Somali 

Region,” August 2, 2012, available from www.gasandoil.com.

321. “Country Profile: Ethiopia,” Cormark Securities, 

February 3, 2011, p. 11.

322. “Operations Ethiopia,” available from www.africaoilcorp.

com.

323. “Geology of Ethiopia—Caleb Hilala Fields,” available 

from https://sites.google.com/site/linkstogeologyofethiopia/Mineral/

calub-hilala-fields.

324. “Country Profile: Ethiopia,” Cormark Securities, 

February 3, 2011, p. 12.

325. “African Oil Farm Out in Ethiopia Closes,” Petroleum 

Africa, October 29, 2012.

326. “Ethiopia,” available from www.afren.com/operations/

ethiopia/.

327. “SouthWest Completes Ethiopia Survey,” Petroleum Africa, February 21, 2012; and “SouthWest Plans Private Placement,” 

Petroleum Africa, December 7, 2012.

328. See sw-oil-gas.com/projects/jijiga-blocks.

329. “Summary of Hydrocarbon Potential in the Ogaden 

Basin,” December 2012, available from sw-oil-gas.com/projects/

gambella-basin.

330. See sw-oil-gas.com/projects/jijiga-blocks.

331. “SouthWest Receives CRP on Ethiopia Blocks,” Petroleum 

Africa, April 10, 2013.

332. “Oil, Gas and Security in Ethiopia,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-Ethiopia.

333. “Ethiopia Oil and Gas Profile,” available from abarrelfull.

wikidot.com/ethiopia-oil-and-gas-profile.
266

334. “Country Profile: Ethiopia,” Cormark Securities, 

February 3, 2011, p. 10.

335. “Calvalley Signs First Production Sharing Contract in 

Ethiopia,” October 20, 2008, available from www.newswire.ca.

336. See sw-oil-gas.com/projects/gambella-basin.

337. “Sabisa-1 Spuds in Ethiopia,” Petroleum Africa, January 

15, 2013.

338. “Africa Oil Updates Ethiopia Action,” Petroleum Africa, 

April 18, 2013.

339. “Tullow Probes the ‘Ramp’ Prospect in Ethiopia,” 

January 27, 2013, available from www.africaoilgasreport.com.

340. “Agriterra Completes Ethiopia Sale to Marathon,” 

Petroleum Africa, February 1, 2013.

341. “Ethiopia,” available from www.tullowoil.com.

342. “Africa Oil Formalizes PSA for Ethiopian Acreage,” Petroleum Africa, February 22, 2013.

343. “Africa Oil Updates Ethiopia Action,” Petroleum Africa, 

April 18, 2013.

344. “Operations Ethiopia,” available from www.africaoilcorp.

com.

345. “Calvalley Signs First Production Sharing Contract in 

Ethiopia,” October 20, 2008, available from www.newswire.ca.

346. “Epsilon Would Consider Partner in Ethiopia,” Petroleum 

Africa, November 3, 2011.

347. Management’s Discussion and Analysis (“MD&A”) for 

the 3 and 9 months ending September 30, 2011, p. 7, available from 

www.epsilonenergyltd.com/pdf_folder/Epsilon-Sept-30-2011-MDAFinal.pdf.
267

348. “Ethiopia: A Potentially Golden Block on East Africa’s 

Tertiary Rift,” March 6, 2013, available from www.oilprice.com.

349. See sw-oil-gas.com/projects/jimma-block.

350. “Gabon—Country Analysis Brief,” Washington, DC: U.S. 

Energy Information Administration, January 17, 2012.

351. “Gabon—Country Analysis Brief,” EIA.

352. “Gabon: World-Class Pre-Salt Potential,” Ophir Energy.

com, p. 21.

353. See www.mbendi.com/land/af/ga/p0005.htm.

354. “Oil, Gas and Security in Gabon,”available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-gabon/.

355. “Gabon—Country Analysis Brief,” EIA.

356. “Gabon Oil and Gas Profile,” available from abarrelfull.

wikidot.com/gabon-oil-and-gas-profile.

357. “Perenco in Gabon,”available from www.perenco-gabon.

com.

358. “Gabon,” available from www.shell.com/global/aboutshell.

359. “News and Media Releases,” July 25, 2012, available 

from www.shell.com.

360. “Overseas oil and Gas Exploration and Development,” 

available from www.sinopecgroup.com.

361. “Gabon Country Overview,” available from www.addaxpetroleum.com/operations/gabon.

362. “Gabon and Addax Locked in Dispute,” Petroleum Africa, 

June 8, 2013.

363. “Upstream Africa Acreage,” Total Factbook 2011.
268

364. “Marathon Oil Announces Re-entry into Gabon,” 

press release, June 22, 2012.

365. “The Mineral Industry of Gabon,” 2010 Minerals 

Yearbook - Gabon, U.S. Geological Survey, August 2012, p. 17.2.

366. “Vaalco Completes Avouma Well,” Petroleum Africa, 

April 17, 2013.

367. “JVs/PSCs/Alliances,” available from www.oil-india.com.

368. “Gabon” available from www.maureletprom.fr.

369. Saurabh Chaturvedi, “Oil India Executive: To Continue 

Talks for Maurel’s Gabon Stake,” Dow Jones, February 18, 2013.

370. “Gabon—betting on the West Coast of Africa,” available 

from www.petrobras.com/en/countries/gabao/gabao.htm.

371. “VAALCO Energy Provides Update on Mutamba Iroru 

Block Onshore Gabon,” press release, November 8, 2012, available from vaalco.investorroom.com.

372. “Pre-salt Discovery in Gabon,” Petroleum Africa, January 

4, 2013.

373. “Gabon: Dussafu,” available from www.harvestnr.com/

operations/gabon.html.

374. “Harvest Natural Updates Gabon Action,” Petroleum 

Africa, May 6, 2013.

375. Cobalt has a 21 percent working interest in Diaba, which 

is operated by Total. See www.cobaltintl.com.

376. “Cobalt Pushes Pre-salt Program in West Africa,” Petroleum Africa, February 28, 2013.

377. “Gabon to Launch Deepwater Licensing Round,” Petroleum Africa, December 4, 2012.

378. “Gabonese License Awards in Offing,” AfrOil, April 

2, 2013.
269

379 . “Pura Vida Awarded Gabon Block,” Petroleum Africa, 

January 16, 2013.

380. “Pura Vida’s Initial Evaluation of the Loba Discovery 

Well,” Petroleum Africa, March 8, 2013.

381. See www.africanpetroleum.com.au/our-projects/gambia.

382. See www.mbendi.com/land/af/gm/p0005.htm.

383. “BOS Scores Contract for Massive Frontier Survey,” 

Petroleum Africa, January 4, 2011.

384. “The Gambia,” available from buriedhill.com/Operations/

The-Gambia/.

385. “CAMAC Enters Gambia, Petroleum Africa, January 

25, 2012.

386. CAMAC Cements Gambia Acreage,” Petroleum Africa, 

May 30, 2012.

387. “Gambia,” available from www.camacenergy.com/gambia.

php.

388. “Ghana Oil Almanac,” p. 13, available from www.openoil.

net.

389. “Ghana’s Upstream/Midstream Activity Map,” Africa 

Oil & Gas, 2012.

390. “Jubilee Sees Record Flows,” Petroleum Africa, December 

20, 2012.

391. Ofonobong Osei-Tutu, “Kosmos Expects 25,000 BOPD 

(Net) in 2013,” March 14, 2013, available from africaoilgasreport.

com/2013/03/in-the-news/kosmos-expects-25000bopd-net-in-2013/.

392. “Ghana Oil Almanac,” p. 13, available from openoil.net/?

wpdmact=process&did=MTYuaG90bGluaw==.
270

393. Ibid., p. 12.

394. “Oil, Gas and Security in Ghana,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-ghana/.

395. “Jubilee Field,” and “Deepwater Tano Block,” available 

from www.kosmosenergy.com.

396. “Ghana Oil and Gas Profile,” available from abarrelfull.

wikidot.com/ghana-oil-and-gas-profile; and “Activities | Exploration 

& Production,” available from www.gnpcghana.com.

397. “Activities|Exploration & Production,” available from 

www.gnpcghana.com.

398. “West Cape Three Points Block,” available from www.

kosmosenergy.com.

399. “Ghana—Recent Oil Discoveries and Exploration Plans 

for 2011,” May 23, 2011, available from www.mergersandacquisitionreviewcom.blogspot.com.

400. “Jubilee Field,” available from www.kosmosenergy.com.

401. “Ghana—2010 [Advance Release],” U.S. Geological Survey Minerals Handbook, p. 19.4. Note: A different source gave the 

shares in Jubilee as Tullow, 36.5 percent; Anadarko and Kosmos, 

23.49 percent each; GNPC, 13.75 percent; and Sabre, 2.81 percent. 

See “Oil & Gas—Ghana and Uganda—the Quick and the Slow,” 

November 18, 2012, available from www.equities.com.

402. “Major Projects” available from www.tullowoil.com.

403. “Tullow Looks to Sell a Piece of TEN,” Petroleum Africa, 

February 15, 2013. 

404. “TEN PoD Gets Nod from Ghana,” Petroleum Africa, May 

31, 2013.

405. “New Discovery May Lead to Fourth Field Development 

Offshore Ghana,” Africa Oil & Gas Journal, August 8, 2012; and 

“Jubilee Sees Record Flows,” Petroleum Africa, December 20, 2012.
271

406. Note: Vitol’s website indicates the firm has a 44.44 percent non-operator interest, with ENI holding a 55.56 percent interest and GNPC a carried 15 percent interest. See “Ghana,” available from www.vitol.com.

407. “ENI Enlarges the Ghanaian Oil Tank,” Africa Oil & Gas 

Report, October 9, 2012.

408. “Ghana’s Upstream/Midstream Activity Map,” Africa 

Oil & Gas, 2012.

409. “ENI Discovers Oil in Tano Basin Offshore Ghana,” September 20, 2012, available from www.epmag.com.

410. Alan Petzet, “Ghana discovery list grows with VancoLukoil Find,” March 15, 2010, available from www.ogj.com.

411. “Ghana—Recent Oil Discoveries and Exploration 

Plans for 2011,” May 23, 2011, available from www.mergersand

acquisitionreviewcom.blogspot.com.

412. “Ghana,” available from www.statoil.com/Annual

Report2011/en/Pages/frontpage.aspx; and “Hess Gets Partner in 

Ghana,” Petroleum Africa, April 27, 2012.

413. “Deepwater Tano/Cape Three Points,” available from 

hess.com/operations/default.aspx.

414. “Ghana’s Offshore Pecan-1 a Hit for Hess,” Petroleum 

Africa, December 13, 2012.

415. “Hess Cracks Nut Discovery Offshore Ghana,” Petroleum 

Africa, March 1, 2013.

416. Alan Petzet, “Vanco, Lukoil find oil off eastern Ghana,” 

February 26, 2010, available from www.ogj.com.

417. “Lukoil Could Resume Ghana Drilling in 4Q,” Petroleum 

Africa, March 29, 2013.

418. “Lukoil Eyes New Ghanaian Drilling,” AfrOil, April 

2, 2013.
272

419. “Aker wins deepwater acreage in Ghana,” available from 

www.akerasa.com/News-Media/Stock-exchange-releases/Agreement/

Aker-wins-deepwater-acreage-in-Ghana/(year)/2013.

420. “Cape Three Points Deep Water Block,” November 6, 

2008, available from www.panatlanticexploration.com.

421. “Offshore Saltpond Basin—Gasop,” available from www.

gasopoil.com.

422. “Hydrocarbon exploration in Ghana,” available from 

www.tullowoil.com.

423. See en.wikipedia.org/wiki/Saltpond_Oil_Field.

424. “Keta Block,” available from www.afren.com/operations/

ghana/keta_block.

425. “Ghana’s Upstream/Midstream Activity Map,” Africa 

Oil & Gas, 2012.

426. “Keta Block,” available from www.afren.com/operations/

ghana/keta_block.

427. “Ghana’s Upstream/Midstream Activity Map,” Africa 

Oil & Gas, 2012.

428. “Ghana - Offshore Accra Block,” available from www.

rialtoenergy.com/index.php?option=com_content&view=article&id=27

&Itemid=27.

429. “Stena signed up for more Ghanaian Drilling,” AfrOil, 

April 9, 2013.

430. “Simba Energy in Ghana,” available from www.

simbaenergy.ca/projects/ghana.aspx.

431. “Oil & Gas—Ghana and Uganda—the quick and the 

slow,” available from www.equities.com.

432. “Ghana’s Upstream/Midstream Activity Map,” Africa 

Oil & Gas, 2012.
273

433. “Jubilee Gas Tagged for Aboadze Power,” Petroleum 

Africa, April 2, 2013.

434. “Ghana-Ivory Coast Border Dispute Doesn’t Distract 

Us—Kosmos Energy,” September 27, 2012, available from www.

ghanaoilwatch.org.

435. “Ivory Coast-Ghanaian Border Dispute,” en.wikipedia.org.

436. “Oil, Gas and Security in Guinea,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-Guinea.

437. “Guinea,” available from www.dana-petroleum.com/

Our-businesses/Africa/Overview.

438. “West Africa Operations,” available from hyperdynamics.

com/guinea_project.htm.

439. Ibid.

440. Guinea—Country Commercial Guide 2012,” U.S. 

Foreign Commercial Service.

441. See www.chinasonangol.com.

442. “Hyperdynamics Announces Updated Prospective Oil Resources Evaluation,” February 14, 2013, 

available from investors.hyperdynamics.com/releasedetailcfm?Release

ID=740406. and “Tullow Agrees to Farm-in Guinea Concession,” 

November 20, 2012, available from www.tullowoil.com.

443. “HyperD’s Guinea Farm-out to Tullow a Done Deal,” 

Petroleum Africa, January 2, 2013.

444. “Guinea: Hyperdynamics Encounters Oil Shows in Sabu1 Well Offshore Guinea-Conakry,” February 15, 2012, available 

from www.energy-pedia.com.

445. “Simba Lands Onshore Guinea,” Petroleum Africa,” July 

29, 2011.
274

446. “Simba Gets Green Light for Onshore Guinea PSCs,” 

Petroleum Africa, May 25, 2012.

447. “Simba Energy Identifies Three Significant Seeps in 

Guinea,” February 27, 2013, available from www.simbaenergy.ca.

448. “Guinea, Bove Basin,” available from www.simbaenergy.

ca/projects/guinea.aspx.

449. “Guinea Hammers Out Petroleum Code-Auction in the 

Works,” Petroleum Africa, November 2, 2012.

450. “Oil, Gas and Security in Guinea-Bissau,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-Guinea-Bissau.

451. “Guinea-Bissau,” available from www.mbendi.com/land/af/

gb/p0005.htm.

452. David Brown, The Challenge of Drug Trafficking to Democratic Governance and Human Security in West Africa, Carlisle, PA: 

Strategic Studies Institute, U.S. Army War College, May 2013.

453. “Svenska Finalizes Data Acquisition Offshore Guinea 

Bissau,” Svenska Petroleum press release, December 10, 2010.

454. Ibid.

455. “Guinea-Bissau,” available from www.far.com.au/guineabissau/. 

456. See www.spherepetroleum.com/Guinea-Bissau/guinea-bissau.

html.

457. “Noble Joins Senegal-Guinea Bissau Exploration,” Oil & 

Gas Journal, June 8, 2011.

458. “Completion of Kora-1 Exploration Well,” Ophir press 

release, July 27, 2011.

459. ““AGC,” available from www.far.com.au.
275

460. “Country Profile: Kenya,” Toronto, Canada: Cormark 

Securities, February 3, 2011, p. 15. 

461. Eduard Gismatullin, “Kenya’s Deepwater Debut Heralds 

East Africa’s First Oil: Energy,” Bloomberg, July 11, 2012.

462. “Kenya Block 2A,” available from www.simbaenergy.ca.

463. “Country Profile: Kenya,” Cormark Securities, February 

3, 2011, p. 15.

464. “Kenya to Gazette up to 9 New Oil and Gas Exploration 

Blocks,” Reuters, February 12, 2013.

465. “Cradle of Mankind and the Next Big Oil Patch,” Bloomberg BusinessWeek, March 18-24, 2013, p. 10.

466. “Kenya,” March 16, 2013, available from www.

camacenergy.com/kenya.php; Gismatullin, “Kenya’s Deepwater 

Debut Heralds East Africa’s First Oil: Energy.” 

467. Angelia Sanders et al., “Emerging Energy Resources in 

East Africa,” Norfolk, VA: Civil-Military Fusion Center Mediterranean Basis Team, September 2012, p. 3.

468. “Kenya to Gazette up to 9 New Oil and Gas Exploration 

Blocks,” Reuters, February 12, 2013.

469. Sarah McGregor, “Kenya Spends $25 Billion on BondBacked Port for Oil: Freight,” September 4, 2012, available from 

Bloomberg.com.

470. “Twiga South-1 Hits Oil,” Petroleum Africa, November 1, 

2012; and “Kenya’s Twiga South-1 Flow tests Complete,” Petroleum Africa, February 22, 2013.

471. “Kenya: Oil Production 6-7 Years Away,” Oilprice.com, 

May 10, 2013.

472. “Kenya,” available from www.tullowoil.com.

473. “Block 12B, Kenya,” available from www.swala-energy.

com.
276

474. “Paipai-1 Well Suspended,” Petroleum Africa, March 

4, 2013.

475. “Africa Oil Completed Deal with Marathon Oil on Kenya 

Blocks,” available from www.equities.com.

476. “Kenya,” available from www.africaoilcorp.com.

477. Sanders et al., “Emerging Energy Resources in East 

Africa,” p. 2.

478. “Seismic Bulks Up Afren’s East African Resource Portfolio,” Petroleum Africa, August 23, 2013.

479. “Overview,” available from taipanresources.com/

operations-overview.html.

480. “Kenya Taipan Resources Completes 2D Seismic Survey in Block 2B onshore Kenya—Commences FTG Survey,” 

March 21, 2013, available from www.energy-pedia.com/news/kenya/

new-153949.

481. “Projects—East Africa Opportunity,” available from 

www.imaraenergy.com/projects/index.php.

482. “Overview,” available from taipanresources.com/

operations-overview.html.

483. “ERHC Signs PSC for Kenyan Acreage,” Petroleum Africa, 

July 10, 2012.

484. “Republic of Kenya,” available from www.erhc.com.

485. “ERHC Signs LoI for Farm Out in Kenya,” Petroleum 

Africa, May 9, 2013.

486. “Kenya, Block 2A,” available from www.simbaenergy.ca/

projects/kenya.aspx.

487. “Africa Oil Completes Deal with Marathon Oil on Kenya 

Blocks,” available from refinerynews.com/africa-oil-completes-dealwith-marathon-oil-on-kenya-blocks/.
277

488. “Simba to Farm Out Kenyan Stake,” Petroleum Africa, 

May 14, 2013.

489. “Oil Industry in Kenya,” available from www.vanoil.ca/s/

Kenya.asp.

490. “Kenya Oil and Gas Profile,” available from abarrelfull.

wikidot.com/kenya-oil-and-gas-profile.

491. “Kenya Assets,” available from www.bowleven.com.

492. “Kenya” [Advance Release], U.S. Geological survey Minerals Yearbook 2010, p. 22.2. Note: One source indicated that CNOOC 

left Kenya after this unsuccessful well, but the firm’s website indicates, without providing any detail, that it still has operations in 

Kenya. See www.cnoocltd.com; “Country Profile: Kenya,” Cormark 

Securities, February 3, 2011, p. 17.

493. “Kenya,” available from investor.apachecorp.com/

releasedetail.cfm?ReleaseID=706491.

494. Sanders et al., “Emerging Energy Resources in East 

Africa,” p. 2.

495. “Kenya—Lamu Basin,” available from www.pancon.com.

au/projects/kenya/lamu-basin-l8-l9/.

496. “Kenya L5, L7, L11A, L11B & L12 Project,” available from 

www.pttep.com.

497. “Kenya,” March 16, 2013, available from www.

camacenergy.com/kenya.php.

498. “CAMAC Commences Kenyan Surveys,” Petroleum 

Africa, April 11, 2013.

499. “FAR Completes 3D Data Acquisition Offshore Kenya,” 

July 12, 2012, available from www.subseaworldnews.com; “Kenya—

Lamu Basin,” available from www.pancon.com/au; and “FAR Sees 

Block L6 Expanded,” Petroleum Africa, March 28, 2013.
278

500. “FAR expands L-6 block off Kenya,” AfrOil, April 2, 2013.

501. “FAR Keen on Kenya/Senegal Drilling Prospects,” Petroleum Africa, February 28, 2013. Also see www.far.com.au/kenya/.

502. “Kenya: Ophir Operated Drilling Programme,” available 

from www.ophir-energy.com. 

503. “Kenya,” available from www.bg-group.com.

504. “Kenya,” available from www.premier-oil.com.

505. “Block L17/L18,” available from www.afren.com/

operations/kenya/block_l17l18/.

506. “Afren Tangos in Tanzania’s Tango Block,” Petroleum Africa, March 25, 2011.

507. “Seismic Bulks Up Afren’s East African Resource Portfolio,” Petroleum Africa, August 23, 2013.

508. “Mineral Fuels”; [Advance Release] U.S. Geological Survey—2011; “Second Discovery Points Liberia As Emerging Western Star,” Africa Oil & Gas Report, March 5, 2013.

509. “Repsol in Liberia,” available from www.repsol.com/es_en/

corporacion/conocer-repsol/repsol-en-el-mundo/liberia.aspx.

510. “Liberia,” available from www.chevron.com; and Christopher Helman, “Chevron Adds Big Acreage Offshore Liberia,” 

Forbes, September 8, 2010.

511. “Liberia on Course to Prove Oil Riches in 2011,” June 

2011, available from mergersandacquisitionreviewcom.blogspot.com.

512. “Updates West Africa Activity,” news release, 

November 9, 2011, available from www.anadarko.com.

513. “Liberia,” available from www.tullowoil.com/index.

asp?pageid=267.
279

514. “African Petroleum Launches Liberia Drilling, Petroleum 

Africa, January 9, 2013.

515. “Liberia’s Bee Eater-1 a Hit for AP,” Petroleum Africa, 

February 20, 2013.

516. “Oil, Gas and Security in Liberia,” available from thinksecurityafrica.org/oilgas/oil-and-gas-in-Liberia. 

517. “Liberia,” available from www.AfricanPetroleum.com.au/

our-projects/liberia.

518. “ExxonMobil Dives in Offshore Liberia,” Petroleum Africa, March 11, 2013; and “Liberia to Ratify PSC for LB-13,” Petroleum Africa, March 28, 2013.

519. “Liberia ratifies Canadian Overseas’ PSC,” AfrOil, April 

2, 2013.

520. “TGS Launches Liberian Campaign,” Petroleum Africa, 

accessed January 22, 2013.

521. “Gas and Security in Liberia,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-Liberia. 

522. “Simba Energy in Liberia,” available from www.

simbaenergy.ca/projects/liberia.aspx.

523. “Libya Oil and Gas Profile,” available from www.abarrelfull.wikidot.com.

524. “Oil, Gas and Security in Libya,” available from thinksecurityafrica.org/oilgas/oil-and-gas-in-Libya.

525. “Country Analysis Briefs—Libya,” EIA, June 2012.

526. Taib, “The Mineral Industry of Libya,” p. 25-1.

527. Christopher Coats, “Libya Protection Falling Short,” 

AfrOil, April 2, 2013.

528. “Country Analysis Briefs—Libya,” EIA, June 2012.
280

529. Taib, “The Mineral Industry of Libya,” p. 25-1.

530. “Country Analysis Briefs—Libya,” EIA, June 2012.

531. Taib, “The Mineral Industry of Libya,” p. 25-1.

532. “Country Analysis Briefs—Libya,” EIA, June 2012.

533. Taib, “The Mineral Industry of Libya,” p. 25-1.

534. “Exploration: Libya Waha,” available from www.hess.

com/operations; and “Libya,” available from www.marathonoil.com/

Global_Operations/Libya.

535. “Libya - Sirte Basin Waha Concession,” available from 

www.conocophillips.com/EN/about/worldwide_ops/other/Pages/Libya.

536. “Exploration: Libya Area 54,” available from www.hess.

com/operations.

537. “Repsol in Libya,” available from www.repsol.com/es_en/

corporacion/conocer-repsol/repsol-en-el-mundo/libia.aspx.

538. Esam Mohamed, “Militiamen Attack Ga Complex in 

Western Libya,” Associated Press, May 20, 2013.

539. “Wintershall in Libya,” available from www.wintershall.

com/en/worldwide/libya.html.

540. “Libya,” available from www.gazprom.com/about/

production/projects/deposits/libya.

541. “Libya,” available from www.suncor.com.

542. “Libya,” available from www.statoil.com/Annual

Report2011/en/Pages/frontpage.aspx.

543. “Upstream Africa Acreage—Libya,” Total Factbook 2011; 

and “Libya,” “Exploration and Production in Africa—Total 

Group,” available from www.total.com.
281

544. “Wintershall in Libya,” available from www.wintershall.

com/en/worldwide/libya.html.

545. “Libya,” available from www.omv.com/portal/01/com/omv/

OMVgroup/Business_Segments/OMV_Exploration_and_Production/

Worldwide_Activities/Libya.

546. “Medco Energi Establishes JOC for Libya Ops,” Petroleum Africa, March 26, 2013.

547. “Libya Oil Development,” available from www.med

coenergi.com/page.asp?id=210028.

548. “JVs/PSCs/Alliances,” available from www.oil-india.com. 

Note: Oil India’s website indicates this NOC is in the process of 

relinquishing area 86 and Clock 102(4). 

549. “CNPC in Libya,” available from www.cnpc.com.cn/en/

cnpcworldwide/libya.

550. See www.gwdc.com.cn.

551. “Oil giant Exxon returns to Libya,” December 6, 2005, 

available from www.bbc.co.uk.

552. “Shell Says Still Interested in Libya Oil Exploration,” 

Reuters, November 7, 2012.

553. See www.upstreamonline.com, October 4, 2010.

554. Christopher Coats, “Libya Protection Falling Short,” 

AfrOil, April 2, 2013.

555. “Libyan protesters end blockage at Waha Oil field,” 

AfrOil, April 2, 2013.

556. Debbie Stevenson, “Investors Make a Move on Madagascar’s Oil Reserves,” November 20, 2012.

557. “Country Profile: Madagascar,” Cormark Securities, February 3, 2011, p. 19.
282

558 . “Oil, Gas and Security in Madagascar,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-madagascar/.

559. “Madagascar Puts Kibosh on Oil Tender,” Petroleum 

Africa, March 7, 2011.

560. Stevenson, “Investors Make a Move on Madagascar’s Oil 

Reserves.” 

561. “Uncertainty Reigns for Madagascar Oil, Petroleum 

Africa, February 10, 2011. See also “Country Profile: Madagascar,” 

Cormark Securities, February 3, 2011, p. 18.

562. “Madagascar Puts Kibosh on Oil Tender,” Petroleum 

Africa, March 7, 2011.

563. “Force Majeure for Madagascar Oil,” Petroleum Africa, 

March 22, 2011.

564. “Madagascar Settles Dispute Over Tsimiroro Block,” 

Petroleum Africa, June 27, 2011.

565. “Madagascar Oil Sees Resolution with OMNIS,” Petroleum Africa, April 6, 2012.

566. “Madagascar Oil See Tsimiroro Resources Rise,” Petroleum Africa, September 13, 2011; and “Focused on the Development of Heavy Oil & and Conventional Oil & Gas,” available 

from www.madagascaroil.com.

567. Madagascar Oil Limited, Securities Announcement of 

Half Year Results, September 28, 2012.

568. EIA Short-Term Energy Outlook (STEO), as provided by 

USAFRICOM source, April 25, 2013.

569. Stevenson, “Investors Make a Move on Madagascar’s Oil 

Reserves.” 

570. “Madagascar,” available from www.total.com.

571. “Total’s Stay Extended on Madagascar Block,” Petroleum 

Africa, July 29, 2011.
283

572. “Madagascar,” January 17, 2013, available from www.

afren.com/operations/madagascar.

573. “Afren Grabs Huge Madagascar Stake,” Petroleum Africa, 

July 26, 2011.

574. “Madagascar,” January 17, 2013, available from www.

afren.com/operations/madagascar.

575. “Caravel launches Seismic in Madagascar,” Petroleum Africa, December 17, 2013.

576. “Petrole et gaz a Madagascar—Behaza Oil Project . . .” 

(“Oil and Natural Gas in Madagascar—Behaza Oil Project . . .”), 

December 19, 2012, available from www.tim-madagascar.org.

577. “Core Assets—Madagascar,” available from www.avanapetroleum.com/islands.

578. “Tullow Looking for Partner in Madagascar,” November 

4, 2011.

579. “Madagascar,” available from www.tullowoil.com.

580. Overseas assets, available from www.essarenergy.com.

581. “Madagascar—Exxon Keeps Eye on Offshore,” January 

18, 2012, available from www.africaintelligence.com.

582. “Madagascar,” Vietnam National Oil and Gas Group, 

available from english.pvn.vn; “Madagascar,” available from www.

bg-group.com.

583. “Madagascar: Ampasindava,” available from www.

sterlingenergyuk.com.

584. “Country Profile: Madagascar,” Cormark Securities, 

February 3, 2011, p. 19.

585. “Madagascar,” available from nikoresources.com/

operations/madagascar.html.
284

586. “Completion of 2-D Seismic Data Acquisition in Juan 

de Nova and Belo Profond Assets,” press release, available from 

www.sapetro.com.

587. “SAPETRO Purchases 90% Interest in Belo Profond Offshore Madagascar,” press release, October 27, 2011, available 

from www.sapetro.com. 

588. “Completion of 2-D Seismic Data Acquisition in Juan de 

Nova and Belo Profond Assets.” 

589. “Juan de Nova,” available from www.globalpetroleum.com.

au/operations/juan-de-nova.

590. “Juan de Nova Est Mozambique Channel,” available 

from www.wessexexploration.com/JuanDeNova.html.

591. Paul Burkhardt, “SacOil Wins Malawi Block as East African Finds Lure Drillers,” Bloomberg, December 13, 2012.

592. “Award of the Onshore Petroleum Prospecting License 

Block 1 in Malawi,” December 13, 2012, available from www.

sacoilholdings.com. 

593. “Surestream Petroleum Awarded Exploration Licenses 

in Malawi,” September 22, 2011, available from www.surestreampetroleum.com.

594. Robyn Curnow et al., “Troubled Water: Oil Search Fuels 

Tension Over Lake Malawi,” CNN, November 14, 2012.

595. Tanzania Calls on Malawi to Quit Exploring,” Petroleum 

Africa, July 31, 2012; “Tanzania Wants Mediator for Lake Malawi 

Dispute,” Petroleum Africa, October 8, 2012.

596. “Malawi/Tanzania Dispute Widens with New Award,” 

Petroleum Africa, March 1, 2013.

597. “Malawi, Tanzania Head for Court,” AfrOil, April 9, 2013.

598. Abdul Wakil Saiboko, “Tanzania: Lake Nyasa Border 

Dispute Goes to African Forum,” Tanzania Daily News, Decem-
285

ber 29, 2012; and “Malawi/Tanzania Dispute Widens with New 

Award,” Petroleum Africa, March 1, 2013.

599. “Heritage Scores Another Tanzania PSA,” Petroleum Africa, January 26, 2012.

600. “NuEnergy Granted Exclusive Prospecting Licence for 

CBM and Shale Gas Exploration in Malawi,” NuEnergy Company announcement, July 9, 2012.

601. “NuEnergy Launches Malawi Airborne Survey,” Petroleum Africa, May 17, 2013.

602. “Oil, Gas and Security in Mali,” available from www.

thinksecurityafrica.org/oilgas/oil-and-gas-in-Mali.

603. “Mali,” available from afexglobal.com/operations/mali.

604. “Mali—A Developing Oil and Gas Industry,” Mali Republic Minister of Mines, Energy and Water, presentation to Corporate Council on Africa conference, November 29, 2006.

605. “ENI Pulls Out of Mali on Poor Prospecting Outlook,” 

Reuters, January 15, 2013.

606. “Angola Enters Mali,” Petroleum Africa, November 

8, 2011.

607. “Simba Receives PSA Approval from Mali,” Petroleum 

Africa, October 2011.

608. Homepage, available from www.spherepetroleum.com.

609. Map, “Simba Energy in Mali,” available from www.

simbaenergy.ca/projects/mali.aspx.

610. Pav Jordan, “Iamgold to Cut Back Mali Exploration 

Activity,” Globe and Mail, January 23, 2013.

611. “A propos de Petroma” (“About Petroma”), available 

from www.petroma-mali.com/fr/.
286

612. “Mali,” available from afexglobal.com/operations/mali.

613. “Mauritania, Benin, and Togo: Overview of Oil and 

Gas Discoveries and Exploration in 2011,” available from 

mergersandacquisitionreviewcom.blogspot.com/2011/06/

mauritania-benin-and-togo-overview-of.html.

614. “Oil, Gas and Security in Mauritania.” available from 

www.thinksecurityafrica.org.

615. “Mauritania, Benin, and Togo: Overview of Oil and 

Gas Discoveries and Exploration in 2011,” available from 

mergersandacquisitionreviewcom.blogspot.com/2011/06/

mauritania-benin-and-togo-overview-of.html.

616. “Mauritania,” available from www.tullowoil.com.

617. “CNPC in Mauritania,” available from www.cnpc.com.cn/

en/cnpcworldwide/mauritania.

618. ““Update on DNPCIM-operated Heron-1 in Mauritania,” Petroleum Africa, January 17, 2007.

619. “Successful Cormoran-1 Exploration Well Offshore Mauritania,” available from www.tullowoil.com.

620. “Mauritania,” available from www.tullowoil.com.

621. “12 month Exploration & Appraisal Programme,” available from www.tullowoil.com.

622. “Kosmos Enters Mauritania,” Petroleum Africa, April 

10, 2012.

623. “Overview—Mauritania,” available from www.chariotoilandgas.com/operations/mauritania.

624. “Total Awarded Two Exploration Licenses in Mauritania, Offshore and Onshore,” news release, January 6, 2012, available from www.total.com.
287

625. “CNPC in Mauritania,” available from www.cnpc.com.cn/

en/cnpcworldwide/mauritania.

626. “Mauritania,” available from www.rwe.com.

627. “Repsol in Mauritania,” available from www.repsol.com.

628. “Total Awarded two Exploration Licenses in Mauritania, 

Offshore and Onshore,” news release, January 6, 2012, available 

from www.total.com.

629. “India to Explore for Oil, Gas Off Mauritius,” July 3, 2003, 

available from www.siliconindia.com.

630.“Mauritius: ONGC Considering Oil and Gas Exploration 

Rights,” July 8, 2007, available from www.energy-pedia.com/news/

mauritius/ongc-considering-oil-and-gas-exploration-rights-.

631. “Historique de l’Exploitation” (“History of Exploration”), Rabat, Morocco : Office National des Hydrocarbures 

et des Mines, available from www.onhym.com/Hydrocarbons/

Explorationhistory/tabid/290/Default.aspx?Cat=3.

632. “Morocco,” available from www.mbendi.com/land/af/mo/

p0005.htm.

633. “Circle Oil Lays Out North Africa Program,“ Petroleum 

Africa, February 20, 2013.

634. “Activites d’Exploration” (“Exploration Activities”), 

Rabat, Morocco: Office National des Hydrocarbures et des 

Mines, available from www.onhym.com/HYDROCARBURES/

Activit%C3%A9sdexploration/Propre%C3%A0lONHYM/tabid/356/

language/en-US/Default.aspx?Cat=28.

635. “Morocco,“ available from www.sanleonenergy.com/

operations-and-assets.aspx/#morocco; and “Award of Additional 

Blocks,” San Leon Energy press release, August 29, 2012.

636. “Oil and Gas,” available from en.wikipedia.org/wiki/

energy_in_Morocco.
288

637. “Operations in Morocco,” available from www.

chariotoilandgas.com.

638. “Chevron Lands Deep Offshore Morocco,” Petroleum 

Africa, January 23, 2013.

639. “Morocco Significant New Play Opportunities,” 

available from www.kosmosenergy.com/operations-morocco.php.

640. “Kosmos’ 3Q Results Are In,” Petroleum Africa, 

November 6, 2012.

641. “Farmout Secures Funding for Multi-Well Drilling Program Offshore Morocco,” Puravida Energy press release, January 

3, 2013.

642. Based on various company websites, including

tangierspetroleum.com, repsol.com, gulfsands.com, longreachoilandgas.

com, cairnenergy.com, chariotoilandgas.com, galpenergia.com, sericaenergy.com. See also “Pura Vida Enters Morocco,” Petroleum Africa, November 21, 2011; and otp.investis.com.

643. “Repsol in Morocco,” available from www.repsol.com/

es_en/corporacion/conocer-repsol/repsol-en-el-mundo/marruecos.aspx.

644. “Presence of Oil and Gas in Morocco,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-morocco/.

645. “Mozambique: Oil & Gas Exploration in 2011-2012,” 

available from mergersandacquisitionreviewcom.blogspot.com/2011/

07/mozambique-oil-gas-exploration-in-2011.html.

646. “Mozambique Expects Megabillions for LNG,” Petroleum 

Africa, February 9, 2012.

647. See www.anadarko.com/Operations/Pages/LNGmozambique.

aspx.

648. “Mozambique,” available from www.anadarko.com/

Operations/Pages/LNGmozambique.aspx.
289

649. “Anadarko Reaches Heads of Agreement with ENI, 

Award Front-end Engineering and Design Contracts,” Anadarko 

News Release, December 21, 2012.

650. “Mozambique Fact Sheet 2013,” Anadarko Petroleum.

651. “Anadarko Considers JV for Mozambique Monetization,” Petroleum Africa, November 29, 2012. 

652. “Indian Firms May Ante up for Mozambique Offshore 

Area 1 Stake,” Petroleum Africa, March 15, 2013.

653. “Anadarko Eyes Japan for Mozambique LNG Sales,” Petroleum Africa, March 14, 2013.

654. “Mozambique: Another Success on Offshore Area 1,” Petroleum Africa, January 17, 2012, available from www.pttep.com.

655. “Oil and Gas—Mergers and Acquisition Review: 

Mozambique Oil & Gas Exploration in 2011,” available from

mergersandacquisitionreviewcom.blogspot.com/2011/07/mozambiqueoil-gas-exploration-in-2011.html.

656. “ENI Adds Trillions to Mozambique Bounty,“ Petroleum 

Africa, December 6, 2012; “ENI’s Coral-3 Adds to Area 4 Bounty,” 

Petroleum Africa, February 26, 2013.

657. Sa’d Bashir, “East Africa on Sale,” Africa Oil & Gas Report, 

May 21, 2013.

658. Justin Scheck et al., “ENI, CNPC Link Up on Mozambique Gas,” Wall Street Journal Europe, March 15-17, 2013. 

659. “Statoil Farms Down in Mozambique License,” August 14, 2012, available from www.statoil.com/en/NewsAndMedia/

News/2013/Pages/02Apr_Mozambique.aspx. “Mozambique,” available from www.tullowoil.com.

660. “Statoil Sells Down Mozambique Stake to Inpex,” Petroleum Africa, April 3, 2013.

661. “Mozambique: Petronas, Total to Explore Offshore Mozambique, ” Oil & Gas Journal, September 24, 2012.
290

662. “Mozambique,” available from www.mbendi.com/land/af/

mz/p0005.htm.

663. “Mozambique Third License Round, Technical Overview,” Maputo, Mozambique: Instituto Nacional de Petroleo, 

June 2008.

664. “Mozambique—2010 (Advance Release),” U.S. Geological 

Survey—Minerals Handbook 2010, p. 31.3.

665. “South Africa’s Sasol Analyzes Condensate Deposits 

in Inhambane, Mozambique,” July 9, 2012, available from www.

macauhub.com.mo/en/2012/07/09/south-africa%e2%80%99ssasol-analyses-condensate-deposits-in-inhambane-mozambique/.

666. “Rovuma Onshore Concession,” available from www.

wentworthresources.com; “Mozambique Rovuma Onshore Project,” 

available from www.pttep.com.

667. “Doing Business in Mozambique: 2011 Country Commercial Guide for U.S. Companies,” Brussels, Belgium: U.S. Foreign Commercial Service.

668. “Oil, Gas and Security in Mozambique,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-Mozambique.

669. Anne Fruhauf, “Mozambique’s Gas Sector: Prospects 

and Perils,” Oxford Energy Forum, Oxford, UK, November 

2012, p. 12.

670. Ibid.

671. “Mozambique Enacts New Tax,” Petroleum Africa, December 20, 2012.

672. “Mozambique to Raise Its Stake Participation,” Petroleum 

Africa, April 30, 2012.

673. “Mozambique’s Master Plan Ready by Year-end,” Petroleum Africa, May 9, 2013.
291

674. “Petrole: Guebuz ecarte la possibilite d’un conflit avec 

la Tanzanie” (“Petroleum: Guebuz Dismisses the Possibility of a 

Conflict with Tanzania”), Xinhua, December 13, 2011.

675. “Chariot/BP Namibia Deal Done,” Petroleum Africa, 

February 3, 2012.

676. “Namibia,” available from www.galpenergia.com.

677. “Namibian Block 0010 Partners Win Farm-Out Approval,” Petroleum Africa, December 24, 2012.

678. Brian Swint, “Chariot Oil & Gas Plans More Namibia 

Wells After Two Dry Holes,” Bloomberg, September 21, 2012.

679. “Oil, Gas and Security in Namibia,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-production-in-namibia/.

680. “Overview Namibia,” “Exploration Detail—Namibia,” 

available from www.chariotoilandgas.com.

681. “Namibia,” available from www.mbendi.com/land/af/na/

p0005.htm.

682. “Regions Petroliferes en Afrique” (“Petroleum Regions 

in Africa”), available from fr.wikipedia.org.

683. “Namibia,” available from www.tullowoil.com.

684. “Namibia—2010” (Advance Release), U.S. Geological Survey Minerals Yearbook, p. 32.3. One news report indicated that Gazprom quit the Kudu project, leaving Namcor to seek a replacement investor. See “Upstream Update: Upsurge in Namibia and 

South Africa,” African Energy, May 2, 2013.

685. “HRT Heralds Return of the Namibian Rush,” Africa Oil 

& Gas Report, March 5, 2013; and “HRT spuds Offshore Namibia,” 

Petroleum Africa, March 27, 2013.

686. “HRT Prepares for Next Namibian Spud,” Petroleum Africa, May 24, 2013.
292

687. “Global Opens Data Room for Namibia License,” Petroleum Africa, January 15, 2013.

688. “Walvis Bay, Offshore Northern Namibia,” available 

from www.pancon.com.au/projects/namibia/walvis-basin.

689. “Company Profile,” available from www.ecooilandgas.com.

690. “18 Block,” “19’S Block,” available from www.

westbridgeweb.com/s/18_block.asp; and www.westbridgeweb.com/s/19_

block.asp.

691. “Two Exploration Licenses Awarded by Government 

of Namibia,” No. 07-12, Paris, France: Maurel et Prom, March 

15, 2012. 

692. “New Farm Out Offshore Namibia,” Petroleum Africa, 

May 2, 2013. Oranto farmed Bermuda-based Acorn Geophysical in May 2013 into its stakes in 2011B/2111A offshore permit in 

Walvis Bay. 

693. “Signet Petroleum Ltd.,” available from www.

poloresources.com/Investments_Signet.htm.

694. “Namibia Approves Serica Energy’s Farm Out,” Petroleum Africa, June 27, 2012, available from www.serica-energy.com.

695. “Tower’s Namibia Deal Approved,” Petroleum Africa, 

February 1, 2013.

696. “EnerGulf Enters Second Renewal in Namibia,” Petroleum Africa, July 31, 2012, available from www.petroleumafrica.com/

energulf-enters-second-renewal-in-namibia/; Block 1711, available 

from www.energulf.com/assets/namibia/.

697. “Pancontinental’s Namibian Block has Big Oil Potential,” 

Petroleum Africa, May 28, 2013.

698. “19’s Block,” available from www.westbridgeweb.com/s/19_

block.asp.
293

699. “Global Reports on Namibia and Juan de Nova,” Petroleum Africa, April 29, 2012.

700. “Namibia: The Next Hot Spot for Oil Exploration in West 

Africa?” Seeking Alpha, October 26, 2011.

701. “Namibia Piles Up the Reserves,” Petroleum Africa, July 

7, 2011.

702. Josh Lewis, “Petrobras Tastes Dust of Namibia,” September 10, 2012, available from upstreamonline.com.

703. “Nimrod a No-Go for Chariot and Partners,” Petroleum 

Africa, September 11, 2012.

704. “Namibia: The Next Hot Spot for Oil Exploration in West 

Africa?”

705. Ibid.; “Namibia: Tapir South Disappoints—Nimrod 

Next,” Petroleum Africa, May 15, 2012.

706. “Republic of Namibia,” available from www.duma.com/

projects/namibia.

707. “Namibia: Owambo Basin Structural Geology Studied,” 

Oil & Gas Journal, available from www.ogj.com/articles/2012/02/

namibia-owambo-basin-structural-geology-studied.html.

708. “HydroCarb Energy Updates Source rock Evaluation for 

its Africa Concession,” November 27 2012, available from www.

hydrocarb.com. 

709. “Duma’s Namibia P10 Resources Rise,” Petroleum Africa, 

December 5, 2012.

710. “Projects: Namibia,” available from www.friplc.com/index.

php/operations/namibia.

711. “Upstream update: Zambia, Malawi, and Botswana,” 

African Energy, May 16, 2013.

712. “Company Profile,” available from www.ecooilandgas.com.
294

713. “Nigerien Hydrocarbon Reserves,” available from wiki.

openoil.net.

714. “Oil, Gas and Security in Niger,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-the-republic-of-niger/.

715. “Nigerian Hydrocarbon Reserves,” available from wiki.

openoil.net.

716. “Sonatrach Operations in Niger,” available from wiki.

openoil.net.

717. “CNCP in Niger,” available from www.cnpc.com.cn/en/

cnpcworlwide/niger/.

718. “CNPC and CPC Corp. To Jointly Explore Niger,” Petroleum Africa, April 3, 2013.

719. “Gazprom Operations in Niger,” available from wiki.

openoil.net.

720. “International Petroleum Snags 4 Blocks in Niger,” Petroleum Africa, December 6, 2012. Subsequent press reports indicated 

that the names of International Petroleum’s 4 blocks are Manga 

1& 2, Aborak, and Tenere Ouest.

721. “Brandenburg Energy Updates on Due Diligence in 

Niger,” Reuters, November 22, 1012.

722. “Niger to Gain Access to Chad-Cameroon Pipeline,” Petroleum Africa, July 3, 2012.

723. Part of NNPC’s inability to fund is cash obligations to 

IOCs is due to rampant corruption inside of the NOC. See Amrita 

Sen, “Nigeria: A New Dawn?” Oxford Energy Forum, Oxford, 

UK: November 2012, p. 20.

724. Ibid.

725. “With $3.5 billion, ConocoPhillips Cashes Out of Algeria, 

Nigeria,” Africa Oil and Gas Report, January 2, 2013.
295

726. “Chevron Nigeria Joins the Divestment Train,” Africa Oil 

& Gas Report, May 30, 2013.

727. The IEA reported that the Nigerian Government loses $7 

billion annually to oil theft and illegal refining, mostly via pipeline damage from sabotage. See www.nigeriaoilandgasintelligence.

com, November 24, 2102.

728. “Nigeria,” EIA Country profile, October 16, 2012.

729. Due in part to MEND attacks, Nigeria’s production fell 

to 1.7 million bpd in 2009, but climbed back over 2 million bpd 

in 2011 after some companies were able to repair damaged infrastructure. See “Nigeria: A New Dawn?” p. 20; and Helen Castell, 

“Nigeria Faces Return to the Bad Old Days,” AfrOil, April 9, 2013.

730. “Nigeria,” EIA Country profile, October 16, 2012.

731. ‘Nigeria Fact Sheet,” April 2012, available from www.

chevron.com.

732. This figure is for crude oil. Total, for example, produced 

in 2011 a total of 287,000 BOE, which includes gas and gas condensates. See “Nigeria,” available from www.total.com.

733. Philip Mobbs, “The Mineral Industry of Equatorial Guinea,” Equatorial Guinea—2011 [Advance Release], U.S. Geological 

Survey Minerals Handbook—2011, p. 33.2.

734. “China Inc. Buys Another 28,000 BOPD of Nigeria’s Production,” January 2, 2013, available from AfricaOilGasReport.com.

735. “With 181,000 BOPD (net), China Becomes the Firth Largest Produce in Nigeria,” AfrOil, April 9, 2013.

736. “CNPC in Nigeria,” available from www.cnpc.com.cn/en/

cnpcworlwide/niger/.

737. “Nigeria,” available from ongcvidesh.com/Assets.aspx?

tab=2.

738. “JVs/PSCs/Alliances,” available from oil-india.com/JVs.

aspx.
296

739. “Nigeria’s Top Twenty Indigenous Crude Oil Producing 

Companies,” Africa Oil & Gas Report, Table, 2012.

740. “About Mart,” available from www.martresources.com.

741. EIA Short-term Energy Outlook (STEO), provided by USAFRICOM, April 26. 2013.

742. “IOCs: 4 million bpd by 2020 impossible under 

PIB,” Vanguard, April 4, 2013, as quoted in www.vanguardngr.

com/2013/04/4mbpd-by-2020-not-feasible-under-pib-iocs/.

743. Moses Aremu, “Nigeria: Oil Production Could Fall to 

1.84 MMBOPD,” Africa Oil & Gas Report, May 2012.

744. “Nigeria,” EIA Country profile, October 16, 2012.

745. “Oil, Gas and Security in Nigeria,” available from thinksecurityafrica.org/oilgas/oil-and-gas-in-Nigeria.

746. “Nigeria,” EIA Country profile, October 16, 2012.

747. “Petrole: Du petrole dans le lac Tchad?” (“Oil: Any Oil

in Lake Chad?”), September 11, 2012, available from www.

zonebourse.com/LONDON-BRENT-OIL-4948/actualite/Petrole--

Du-petrole-dans-le-lac-Tchad-14702549/.

748. “JVs/PSCs/Alliances,” available from www.oil-india.com.

749. “Oil, Gas and Security in Rwanda,” available from www.

thinksecurityafrica.org.

750. “Vanoil Receives Extension in Rwanda,” Petroleum 

Africa, February 1, 2013. 

751. See www.vanoil.ca/s/Rwanda.asp.

752. U.S. Geological Survey Minerals Yearbook 2010 (Advance 

Release), p. 34.2.

753. “Kivuwatt,” available from www.contourglobal.com/

portfolio/?id=11.
297

754. “Uganda/Rwanda Pipeline Seeks Spark of Interest,” 

Petroleum Africa, August 26, 2011.

755. U.S. Geological Survey Minerals Yearbook—2005, p. 4.2.

756. “Commercial Value of Hydrocarbons Found in the 

Nigeria/Sao Tome Joint Area is Still Unknown,” August 22, 

2012, available from www.macauhub.com.mo/en/2012/08/22/

commercial-value-of-hydrocarbons-found-in-the-nigeriasao-tome-jointarea-is-still-unknown/.

757. “AFREN Plc: Operations: Nigeria—Sao Tome and Principe JDZ: JDZ Block 1,” January 13, 2013, available from www.

afren.com.

758. See investorshub.advfn.com/boards/hubstocks.aspx, May 15, 

2012.

759. “AFREN Plc: Operations: Nigeria—Sao Tome and Principe JDZ: JDZ Block 1.” 

760. “Block-2, Nigeria-Sao Tome & Principe, JDZ,” available 

from www.ongcvidesh.com/Assets.aspx?tab=2.

761. “Sinoangol To Being Negotiations for oil block,” African 

Energy, May 2, 2013.

762. Favour Nnabugwu, “Nigeria’s Oranto Petroleum, 

3 Others Grab Sao Tome Oil Blocks,” October 24, 2011, available 

from www.vanguardngr.com/2011/10/nigeria%e2%80%99s-orantopetroleum-3-others-grab-sao-tome-oil-blocks/.

763. “Benin, Burkina Faso, and Sao Tome E Principe—2010 

(Advance Release),” U.S. Geological Survey Minerals Yearbook—2010, p. 4.3. 

764. See www.equatorexploration.com/operations.

765. See erhc.com.
298

766. “Doing Business in Sao Tome and Principe,” 2012 Country Commercial Guide, U.S. Foreign Commercial Service, Chap. 1. 

767. “Sao Tome annonce son port pétrolier en eaux profondes” (“Sao Tome Announces Its Deep-Water Petroleum Port”), 

Agence Ecofin, February 28, 2012.

768. Africa Fortesa Corporation, available from www.fortesa.

com.

769. “Senegal—Overview of Oil and Gas Exploration and 

Main Players,” June 2011, available from mergersandacquisition

reviewcom.blogspot.com/2011/06/senegal-overview-of-oil-and-gas.html.

770. U.S. Geological Survey Minerals Yearbook—2010, Advance 

Release, p. 18.4.

771. See www.tullowoil.com/.

772. “Cairn Energy Unveils Deal in Senegal . . .” available 

from www.theguardian.com/business/marketforceslive/2013/mar/19/

cairn-energy-senegal-greenland.

773. See www.far.com.au/senegal/.

774. “Elenilto Lands PSC in Senegal,” Petroleum Africa, 

January 2, 2013.

775. See www.elenilto.com/projects/oil-gas/senegal/.

776. Even in English, the JDZ is often referred to by its French 

acronym AGC, or Agence de Gestion et de Cooperation, which 

actually refers to the Joint Commission that manages the JDZ.

777. See www.ophir-energy.com/about-us/who-we-are.aspx.

778. “Oil, Gas and Security in Senegal,” available from www.

thinksecurityafrica.org.

779. “Seychelles Sees its First 3D Shoot,” Petroleum Africa, 

December 13, 2012.
299

780. “Seychelles MC2D Ready for Processing,” Petroleum 

Africa, July 20, 2011. 

781. “Offshore Seychelles a ‘Flagship’ Project,” 

available from www.whlenergy.com/irm/content/seychelles.

aspx?OriginalCategoryId=220.

782. “Seychelles Delays New Block Licensing,” Petroleum 

Africa, November 5, 2012.

783. George Thande, “Seychelles To Change Oil Laws, Invite 

Exploration Bids,” Reuters, March 13, 2013.

784. “Seychelles to Revamp PSAs,” Petroleum Africa, March 

15, 2013.

785. U.S. Geological Survey, Minerals Yearbook 2011.

786. “WHL Delivers on 3 Initiatives in Seychelles,” Petroleum 

Africa, October 11, 2012.

787. “Resource Report on Seychelles Potential,” Petroleum 

Africa, November 11, 2011.

788. “WHL Energy Closes In on Seychelles Farm-In Partner,” 

AfrOil, April 2, 2013.

789. “Seychelles Sees its First 3D Shoot.” 

790. “Seismic Bulks Up Afren’s East African Resource Portfolio,” Petroleum Africa, August 23, 2013.

791. See www.afren.com/operations/seychelles/; “Frontier Exploration,” GEO ExPro, May 2006, p. 42.

792. See www.afren.com/operations/seychelles/.

793. “Frontier Exploration,” GEO ExPro, May 2006, p. 42.

794. “Jupiter-1 Hits Oil Offshore Sierra Leone,” Petroleum 

Africa, February 22, 2012; Sierra Leone, available from www.

petroleumafrica.com/jupiter-1-hits-oil-offshore-sierra-leone/.
300

795. See www/africanpetroleum.com.au/our-projects/sierra-leone.

796. U.S. Geological Survey Minerals Yearbook—2011, Advance 

Release, p. 35.5; “Oil exploration in Sierra Leone in 2011 . . . 

Maybe a New Frontier,” June 14, 2011, available from mergersand

acquisitionreviewcom.blogspot.com/2011/06/sierra-leone-war-povertyand-oil.html.

797. See www.elenilto.com/projects/oil-gas/sierra-leone.

798. “Chevron Awarded Deepwater Interest Offshore Sierra 

Leone,” September 26, 2012, available from www.chevron.com; “Sierra Leone Teamed Various Oil Block Bidders Together for Four 

of the Block, Telling Them to Move Forward as Partners in Negotiation,” August 21, 2012, available from www.thisissierraleone.com.

799. See www.thisissierraleone.com/talisman-energy-sells-downblock-sl-4b-10-in-sierra-leone/, November 8, 2012.

800. “Jupiter-1 Hits Oil Offshore Sierra Leone,” Petroleum 

Africa, February 22, 2012, available from www.repsol.com/es_en/. 

See also www.repsol.com/es_es/corporacion/conocer-repsol/repsol-enel-mundo/sierra-leona.aspx.

801. “Sierra Leone to See $100 million from Lukoil.” Petroleum 

Africa, October 21, 2011; and “Projects—SL-5-11 Block,” available 

from www.panatlanticexploration.com.

802. “Lukoil and Vanco Land in Sierra Leone,” Petroleum 

Africa, July 22, 2011.

803. See www.repsol.com/es_es/corporacion/conocer-repsol/repsolen-el-mundo/tunez.aspx.

804. Angelia Sanders et al., “Emerging Energy Resources in 

East Africa,” Norfolk, VA: Civil-Military Fusion Center Mediterranean Basis Team, September 2012, p. 3.

805. “Oil, Gas and Security in Somalia,” available from www.

thinksecurityafrica.org.

806. See www.mbendi.com/land/af/so/p0005.htm.
301

807. Sanders et al., “Emerging Energy Resources in East 

Africa,” p. 3.

808. William Macpherson, “New Somali Government Looks 

to Revive Oil Search,” African Energy, May 16, 2013.

809. “Somaliland’s Door is Open for Investors,” November 2, 

2012, available from Somalilandpress.com.

810. “Somalia/Kenya Maritime Dispute Heating Up,” Petroleum Africa, July 10, 2012.

811. “Competent Person’s Report of Certain Properties in 

Puntland, Somalia as of 31st December 2010,” Alton, UK: Gaffney, 

Cline & Associates, May 2011, p. 8.

812. See en.wikipedia.org/wiki/Energy_in_Somalia#Energy.

813. “Operations Somalia (Puntland),” available from www.

www.africaoilcorp.com/s/current-activities.asp.

814. “Somalia Spuds First Well in Decades,” Petroleum Africa, 

January 17, 2012.

815. “Oil, Gas and Security in Somalia,” available from www.

thinksecurityafrica.org.

816. “Range To Merge with Timis Company,” African Energy, 

May 2, 2013.

817. See www.hornpetroleum.com/s/Dharoor_Nugaal_Block.asp?

ReportID=499459&_Type=Dharoor-and-Nuggal-Blocks&_

Title=Block-Summaries.

818. “Horn Petroleum Third Quarter 2012 Results,” Horn 

Petroleum news release, November 20, 2012.

819.”Puntland Drilling Reveals Active System,” Petroleum 

Africa, April 13, 2012.

820. See www.redemperorresources.com/irm/content/puntland.

aspx?RID=216.
302

821. “What Puntland Success Could Mean,” Petroleum Africa, 

February 8, 2012.

822. “Somalia (Puntland),” available from www.africaoilcorp.

com/s/current-activities.asp.

823. “Shabeel North Plugged in Puntland,” Petroleum Africa, 

August 28, 2012.

824. Sanders et al., “Emerging Energy Resources in East 

Africa,” p. 3.

825. “Somaliland: Genel Energy to Farm-In to Jacka Resources Odewayne Block, Somaliland,” November 12, 2012, available from www.energy-pedia.com/news/

somaliland/new-152401. and “Odewayne Block Overview,” 

November 14, 2012, available from www.jackaresources.com.au.

826. “Somaliland,” available from www.genelenergy.com/

operations/somaliland.aspx.

827. “Jacka Moves Toward Seismic in Somaliland,” Petroleum 

Africa, March 7, 2013.

828. See www.ophir-energy.com/our-assets.aspx.

829. “Somalia: DNO International Takes Somaliland Block,” 

African Energy, May 2, 2013.

830. “Oil, Gas and Security in South Africa,” available from 

www.thinksecurityafrica.org.

831. “Petroleum Exploration and Production Activities in 

South Africa,” available from www.impactoilandgas.co.uk. 

832. “ExxonMobil to Explore Offshore South Africa,” 

December 17, 2012, available from news.exxonmobil.com.

833. “Exxon Extends Africa’s Energy Enterprise,” UPI, 

December 21, 2012.
303

834. See www.impactoilandgas.co.uk.

835. See www.petrosa.co.za/products_and_services/Pages/Crude.

aspx.

836. Country Report on South Africa, Washington, DC: U.S. 

Energy Information Administration, updated January 17, 2013.

837. “Sunbird Executes Agreement to Acquire 870 Bcf Ibhubesi Gas Project Offshore South Africa,” Sunbird Energy ASX 

Announcement, December 21, 2013.

838. “Exxon Extends Africa’s Energy Enterprise.” 

839. “PetroSA and Cairn India Sign Agreement for Block 1 in 

South Africa,” PetroSA/Cairn joint press release, August 16, 2012.

840. “Sunbird Executes Agreement to Acquire 870 Bcf Ibhubesi Gas Project Offshore South Africa.” 

841. “Thombo Launches South Africa Shoot,” The Petroleum 

Professional, January 29, 2013.

842. See www.afren.com/operations/south_africa/block_2b/. 

843. “Falcon and Chevron Join Forces in Karoo Basin,” Petroleum Africa, December 13, 2012.

844. See www.falconoilandgas.com/karoo-basin-sa.

845. “Chevron Joint Shale Hunt in South Africa,” The Wall 

Street Journal, December 14, 2012.

846. See www.shell.com/zaf/aboutshell/shell-businesses/e-and-p/

karoo/karoo.html.

847. “Kinetiko Updates its Amersfoort Ops,” Petroleum Africa, 

February 21, 2013.

848. See kinetiko.com.au/projects/amersfoort-project.html.

849. Country Report on South Africa, EIA.
304

850. “Sudan and South Sudan,” Country Analysis Briefs, 

Washington, DC: U.S. Energy Information Administration, updated March 19, 2012.

851. “Resuming South Sudan Exports Hits Snag,” Petroleum 

Africa, November 29, 2012.

852. “South Sudan to Export Crude Oil by Road Through 

Ethiopia,” Pan-African News, March 2, 2013.

853. Sanders et al., “Emerging Energy Resources in East 

Africa,” p. 3.

854. “Oil, Gas and Security in Sudan and South Sudan,” available from www.thinksecurityafrica.org.

855. Jill Shankleman, “Oil and State Building in South 

Sudan—New Country, Old Industry,” Washington, DC: United 

States Institute of Peace, July 2011, p. 1.

856. “Pipeline in the Works for South Sudan,” Petroleum 

Africa, February 21, 2013.

857. Kelly Gilblom, “South Sudan Says Oil Pipeline via Kenya 

to Cost $3 Billion,” Reuters, August 10, 2012.

858. “South Sudan in Ethiopia-Djibouti Oil Pipeline Deal,” 

BBC News, February 9, 2012; Jared Ferrie, “China to Loan South 

Sudan $8 Billion for Infrastructure Projects,” Bloomberg, April

28, 2012.

859. Bill Farren-Price, “The Sudanese Struggle for Stability: Long-Term Energy Security Hinges on Deeper Bilateral Political Progress,” Oxford Energy Forum, Oxford, UK, November 

2012, p. 24. 

860. “South Sudan and Sudan Reach Oil Flow Agreement,” 

Petroleum Africa, March 13, 2013.

861. EIA Short-term Energy Outlook (STEO), provided to author by USAFRICOM source on April 25, 2013.
305

862. “Sudan Signs Oil, Gas Exploration Deal in North East,” 

Reuters, August 19, 2010; and “Khartoum,” available from www.

fennocaledonian.com.

863. “Sudan and South Sudan,” Country Analysis Briefs, EIA.

864. “Sudan and Brazil to Cooperate,” Petroleum Africa, 

November 27, 2012.

865. “Sudan Adds to Production,” Petroleum Africa, December 

28, 2012.

866. See en.wikipedia.org/wiki/South_Kordofan.

867. Note: The South Sudan assets of Sudapet were transferred to Nilepet, the new South Sudan NOC, per “South Sudan,” 

available from www.ongcvidesh.com/Assets.aspx?tab=2.

868. “Sudan and South Sudan,” Country Analysis Briefs, EIA; 

“Exploration and Production—South Sudan,” available from 

www.trioceanenergy.com.

869. “ONGC Videsh Limited,”available from www.ongcindia.

com. 

870. “Upstream Africa Acreage—A New Hub for the Group 

in East Africa,” Total Factbook 2011. 

871. Jen Alic, “Desperate South Sudan Carves Up Total Concession,” November 8, 2012, available from www.oilprice.com.

872. Jenny Gross, “South Sudan Offers Total Block to Exxon, 

Kuwait Petroleum,” September 14, 2013, available from www.

rigzone.com.

873. “Total to Bring ExxonMobil and Kufpec into South 

Sudan,” Petroleum Africa, June 4, 2013.

874. “Tanzania Gas Bounty Leads to New Regulations,” Petroleum Africa, June 20, 2012. Note: This 34 tcf figure comes from the 

28.74 tcf figure cited in this article, plus the 5 tcf in new discoveries announced by Statoil in December 2012 and February 2013. 
306

875. “2012 Tanzania Country Commercial Guide,” Washington, DC: U.S. Foreign and Commercial Service (USFCS).

876. “Ophir Energy Reveals Jodari Field Discoveries,” December 14, 2012, available from www.bg-group.com/288/where-we-work/

tanzania/. “Papa-1—Play Opening First Cretaceous Gas Discovery 

Outboard of the Rufiji Delta, Block 3, Tanzania,” Ophir Energy 

PLC, press release, August 2, 2012.

877. “Tanzania: Commercializing Gas,” Ophir presentation to 

Investors, 2012.

878. “Ophir Lines up New Drilling in Tanzania,” Petroleum 

Africa, April 11, 2013. 

879. “BF Completes Tanzania’s Mzia Well Test,” Petroleum 

Africa, May 2, 2013.

880. “Ophir Raises Block 1 Reserves Estimate,” African 

Energy, May 16, 2013.

881. Gismatullin, “Kenya’s Deepwater Debut Heralds East 

Africa’s First Oil: Energy.” 

882. Eduard Gismatullin and Brian Swint, “Statoil $1.2 billion 

Tanzania Find May Hold Oil in New Play,” Bloomberg, February 

24, 2013; “New Discovery for Statoil and ExxonMobil Off Tanzania,” Petroleum Africa, December 24, 2012; “Statoil and ExxonMobil Knock Out Tanzania Discovery,” Petroleum Africa, March 

19, 2013.

883. “BG to Present LNG Terminal to Tanzanian Officials,” 

Petroleum Africa, May 3, 2013.

884. “Rovuma PSA,” available from www.solooil.co.uk. See 

also www.aminex-plc.com; and “Aminex Continues Farm Out Discussions in Tanzania,” Petroleum Africa, March 22, 2013. 

885. Tanzania to Increase Royalties and Fees,” Petroleum 

Africa, July 30, 2012.

886. Ibid.
307

887. “Tanzania Vows No Contracts to Be Revoked,” Petroleum 

Africa, September 20, 2012.

888. Sa’d Bashir, “East Africa on Sale,” Africa Oil & Gas Report, 

May 21, 2013.

889. “Tanzania to Offer New Deepwater Acreage,” Petroleum 

Africa, July 16, 2012.

890. “Afren Tangos in Tanzania’s Tango Block,” Petroleum 

Africa, March 25, 2011.

891. “Tanzania,” available from www.maureletprom.fr.

892. “Kilosa-Kilombero Licence,” “Pangani Licence,” available from www.swala-energy.com.

893. “Tanzania,” available from nuenergygas.com/projects/

eastern-africa/.

894. “Tanzania to Award Acreage to Total,” Petroleum Africa, 

February 14, 2013.

895. “Jacka Acquires Ruhuhu Block in Tanzania,” Petroleum 

Africa, March 21, 2013.

896. U.S. Geological Survey Minerals Yearbook—2010, p. 39.4.

897. “Tanzania Sees Orca Spud,” Petroleum Africa, February 

8, 2012.

898. Maurel et Prom’s website indicates that it also has a 48.06 

percent ownership share in a production permit for Mnazi Bay. 

“Tanzania,” available from www.maureletprom.fr. 

899. “Large-scale Gas Monetization Projects,” available from

www.wentworthresources.com/large-scale.php.

900. “$1.225 bn Deal for Gas Pipeline Inked,” June 23, 2012, 

available from www.tanzanianews24.com.
308

901. “ENI Confirme l”Existence de Petrole au Large du Togo” 

(“ENI Confirms Existence of Oil Along Togo Coast”), Agence 

Ecofin, June 9, 2012.

902. “Le Groupe ENI se prepare a forer un second bloc pour 

le petrole offshore Togolais” (“Togo : ENI Group Prepares to Drill 

Second Well for Offshore Togolese Oil”), Xinhua, January 3, 2012; 

“Togo Asset Overview,” DGS Energy Oil & Gas.

903. “Mauritania, Benin and Togo: Overview of Oil and 

Gas Discoveries and Exploration in 2011,” available from 

mergersandacquisitionreviewcom.blogspot.com/2011/06/

mauritania-benin-and-togo-overview-of.html.

904. “ENI Discovers Oil in Tano Basin Offshore Ghana,” 

available from www.epmag.com. 

905. “Tunisian Oil and Gas,” available from deplc.com/

tunisian-oil-and-gas.

906. “Regions Petroliferes en Afrique” (“Petroleum Regions 

in Africa”), available from fr.wikipedia.org.

907. “Tunisia,” U.S. Geological Survey Minerals Yearbook—

2010, p. 40.3.

908. “Repsol in Tunisia,” available from www.repsol.com; 

“Tunisia,” available from www.chinookenergyinc.com; “Our Operations,” available from www.cooperenergy.com.au/; “Assets in 

Tunisia,” available from www.dno.no; “Tunisia,” available from 

www.paresources.com; “Latest News,” available from www.sondere

sources.com/; “Chorbane Permit—Onshore Tunisia (70%),” available from www.gulfsands.com/s/Tunisiaasp; “Tunisia,” Vietnam 

National Oil and Gas Group, available from english.pvn.vn. 

909. “Tunisia,” available from www.mbendi.com/land/af/tu/

p0005.htm.

910. “Tunisian Oil and Gas,” available from deplc.com/

tunisian-oil-and-gas.

911. “Tunisia,” available from www.bg-group.com/237/wherewe-work/tunisia/.
309

912. “Tunisian Premium Welcome at Chinook,” AfrOil, April 

2, 2103.

913. “Uganda—Disposal of the Interests in Blocks 1 and 3A,” 

available from www.heritageoilplc.com/about-us/history.aspx.

914. “Uganda,” available from www.tullowoil.com.

915. “Tullow Files Suit Against Uganda,” Petroleum Africa, 

December 18, 2012.

916. “The Business Case for Large Scale Uganda Refinery, 

Africa Oil and Gas Report, #9, December 2012.

917. “Museveni Set on a Refinery for Uganda,” Petroleum 

Africa, December 24, 2012.

918. “Uganda Reaches Agreement on Refinery,” Petroleum 

Africa, April 17, 2013.

919. “Uganda MOU on the Way for Lake Albert Partners,” 

Petroleum Africa, May 9, 2013.

920. “Uganda: Export Pipeline is the Bankable Asset,” Africa 

Oil and Gas Report, October 16, 2012.

921. Tabu Butagira, “Museveni Strikes Deal on Oil and Arms 

with Russia,” Africa Review, December 12, 2012.

922. “Analysis: New Law Fails to East Oil Concerns in Uganda,” Nairobi, Kenya: Integrated Regional Information Network 

(IRIN), December 13, 2012.

923. “Uganda Oil and Gas Exploration in 2011 & 2012,” July 

15, 2011, available from mergersandacquisitionreviewcom.blogspot.

com/2011/07/uganda-oil-and-gas-exploration-in-2011.html.

924. “13 Blocks to be Offered by Uganda,” Petroleum Africa, 

January 25, 2013.

925. “Uganda,” available from www.tullowoil.com.
310

926. Sanders et al., “Emerging Energy Resources in East 

Africa,” September 2012, p. 4.

927. Uganda country report, U.S. Geological Survey Minerals 

Yearbook—2011, p. 42.2.

928. Eduardo Pereira and Elison Karuhanga, “Brazil and 

Uganda: Government Intervention and Oil Development Prospects,” Oxford Energy Forum, Oxford, UK, November 2012, p. 18.

929. “Uganda’s Reserves Rise but Development Stalls,” Petroleum Africa, September 18, 2012.

930. “Uganda Appoints Panel for Oil Development,” Petroleum Africa, July 9, 2012.

931. “Oil & Gas—Ghana and Uganda—The Quick and the 

Slow,” November 18, 2012, available from www.thefreelibrary.com/

Ghana+and+Uganda--the+quick+and+the+slow.-a0309793722.

932. EIA Short-Term Energy Outlook (STEO), as provided to 

author by source at USAFRICOM on April 25, 2013.

933. Ben Shepherd, “Oil in Uganda—International Lessons 

for Success,” London, UK: Chatham House, February 2013.

934. “Morocco and Western Sahara 2010 (Advance Release),” 

New Cumberland, PA: U.S. Geological Survey, p. 30.5.

935. “Has Total Re-entered the Disputed Western Sahara?” 

Petroleum Africa, November 30, 2012.

936. “Western Sahara Northwest Africa,” available from 

www.wessexexploration.com.

937. “Saharawi Arab Democratic Republic (SADR),” available 

from www.ophir-energy.com/about-us/who-we-are.aspx.

938. “Premier Buys into West African Assets,” press release, 

May 28, 2003, available from www.premier-oil.com/premieroil/media/

press/premier-buys-into-west-african-assets.
311

939. “Oil, Gas and Security in Zambia,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-zambia/.

940. Maxwell M.B. Mwale, Statement before Zambia’s Parliament on the “Status of Petroleum Exploration in Zambia,” Minister of Mines and Mineral Development, 2010, available from 

www.parliament.gov.zm.

941. “Zambia,” available from www.petrodel.com.

942. Mwale.

943. “Frontier Resources Scores Zambia Block,” Petroleum Africa, April 14, 2011. Note: Another source, the Lusaka Times, indicated that the Zambian Government issued 11 licenses in 2011, 

not three (“State to Revoke License for Oil, Gas Prospectors,” September 21, 2012, available from www.lusakatimes.com).

944. “Oil and Gas potential in Zambia, Malawi, and Botswana,” African Energy, May 16, 2013.

945. “State to Revoke License for Oil, Gas Prospectors.”

946. “Zambia Says Use It or Lose It,” Petroleum Africa, 

February 5, 2013.

947. “Projects: Zambia,” available from www.friplc.com/pdf/

projects/gravity-survey-zambia.pdf.

948. “Frontier Progresses Zambia Exploration,” Petroleum 

Africa, September 7, 2011.

949. “Oil, Gas and Security in Zimbabwe,” available from 

thinksecurityafrica.org/oilgas/oil-and-gas-in-zimbabwe/.

950. “Zimbabwe Exploring for Oil and Gas in Zambezi 

Valley—Mpofu,” December 27, 2011, available from www.

bulawayo24.com.

951. Ibid.

313

APPENDIX II

DEFINITIONS OF OIL AND GAS “RESERVES”

AND QUALITIES OF CRUDE OIL1

Reserves.

The most widely used definitions today of reserves 

are from the Petroleum Resources Management System of the American Society of Petroleum Engineers 

(SPE). According to SPE Guidelines, “reserves” are 

a subset of “resources,” representing the part of resources that are commercially recoverable and have 

been justified for development. Reserves can be subsequently divided into the following three categories, 

depending on certainty of recovery:

1. Proved Reserves. The highest valued category 

of reserves is “proved” reserves. Proved reserves have 

a “reasonable certainty” of being recovered, which 

means a high degree of confidence that volumes will 

be recovered. Reserves must have all commercial aspects addressed.

2. “Probable” or “Possible” Reserves. A lower category of reserves, commonly combined and referred 

to as “unproved reserves,” with decreasing levels of 

technical certainty. Probable reserves are volumes that 

are defined as less likely to be recovered than proved, 

but more certain to be recovered than “possible reserves.” Possible reserves are reserves which analysis 

of geological and engineering data suggests are less 

likely to be recoverable than probable reserves. “2P” 

is used to denote the sum of proved and probable reserves. The best estimate of recovery from committed 

projects is generally considered to be the 2P sum of 

proved and probable reserves.
314

3. Resources. Denotes less certainty than “reserves” because some significant commercial or technical hurdle must be overcome prior to there being 

confidence in the eventual production of the volumes. 

A sub-category is contingent resources, which are 

potentially recoverable but not yet considered mature 

enough for commercial development due to technological or business hurdles. Another sub-category is 

prospective resources. Estimated volumes associated 

with undiscovered accumulations. These represent 

quantities of petroleum that are estimated, as of a given date, to be potentially recoverable from oil and gas 

deposits identified on the basis of indirect evidence 

but which have not yet been drilled. This class represents a higher risk than contingent resources since the 

risk of discovery is also added.

Crude Oil Qualities.

1. Density. Oil density is generally expressed in 

degrees using an API scale. This is a specific gravity 

scale developed by the American Petroleum Institute 

(API), designed to measure the relative density of 

various petroleum liquids. The measure is expressed 

in degrees and most values fall between 10° and 70° 

API gravity. The specific gravity of oil is its relative 

density to water at 60° Fahrenheit.

2. Light oil. Otherwise known as “conventional 

oil,” or “sweet crude,” light oil has an API gravity of 

22° or over. For example, the oil produced from Libyan fields is typically very “light,” and the country’s 

nine export grades have API gravities that range from 

26-43.

3. Heavy oil. Dense, viscous oil with low API gravity. Definitions vary, but it is generally accepted that 
315

the upper limit for heavy oils is 22° API. In Venezuela 

for example, the Bachaquero heavy crude oil has an 

API gravity of 17o. Heavy oils are usually not recoverable in their natural state through a well or by using 

ordinary production methods. Most need to be heated 

or diluted so that they can flow into a well or through 

a pipeline.

4. Extra heavy oil. Extra heavy oil has an API gravity of less than 10°.

5. Bitumen. Otherwise known as “oil sands,” bitumen shares many attributes of heavy oil, but is even 

more dense and viscous.

ENDNOTE - APPENDIX II

1. “Petroleum Resources Management System,” World Petroleum Council, undated paper, 49 pgs.
U.S. ARMY WAR COLLEGE

Major General Anthony A. Cucolo III

Commandant

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STRATEGIC STUDIES INSTITUTE

and

U.S. ARMY WAR COLLEGE PRESS

Director

Professor Douglas C. Lovelace, Jr.

Director of Research

Dr. Steven K. Metz

Author

David E. Brown

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Publications Assistant

Ms. Rita A. Rummel

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Composition

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This Publication SSI Website USAWC Website

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