NOCs evolving as their reach continues to grow

HENRY TERRELL, News Editor

International oil companies (IOCs) have an odd and uncertain relationship with the countries in which they are headquartered and do business. At least in the West, they are often viewed with suspicion, requiring a strenuous and sometimes futile public relations effort to counteract.

Nothing could be less true of the national oil companies (NOCs) of the Middle East, Latin America, Africa and Asia. Generally speaking, these oil goliaths enjoy a prestige in their home countries that is unmatched by any other entity. Quite often they are the countries’ most generous and most reliable employers. Moreover, they benefit from national pride, of which they are symbols. This is largely true throughout the world, even though the great era of nationalization was long ago. It holds true even if the companies are inefficient, poorly run or stifled by corruption. Because of the money they produce for the state, unbusiness-like attributes can be overlooked and forgiven.

For the same reasons, when the shoe is on the other foot—when NOCs branch out to other countries and regions—the same nationalist identity can make them seem doubly threatening. (Recall the furor that erupted in 2005 when China National Offshore Oil Corp. attempted to purchase Unocal.) As NOCs grow larger and richer, and most importantly as they gain expertise, the call of opportunities beyond their own shores will continue to grow. Therefore, the trend of NOCs  behaving more and more like major international oil companies leads invariably to a hybrid category—the international/national oil company, or INOC. The number of companies that fit this definition grows every year.

In the early 1960s only about 15% of world oil reserves were controlled by NOCs, with  IOCs  having total or good access to the remainder. Today, NOCs control 88% of reserves, and they are responsible for just over half of world oil production, according to the US Energy Information Administration.

BEFORE THE NOCS

In the decades bracketing World War I, the world’s economic structure shifted from one in which petroleum was just one of a basket of energy sources to one so dependent on oil that this dependence dictated the course of history. As factories and steamships shifted away from reliance on coal to the more transportable and efficient liquid hydrocarbons, governments scrambled to ensure supplies. Except for the United States, the Western countries depended almost exclusively on imports.

Fig. 1. The first commercial oil well in Saudi Arabia was the Dammam No. 7,  which struck oil in March 1938. At first, Saudi oil potential was not considered very promising.

The concession system developed to meet this demand. In the classic (some would say cartoon) version, large private companies, with the open and active support of colonial governments, obtained generous concessions giving them a free hand to exploit and export oil as they saw fit. In return, these often repressive governments could count on outside help, economic and military, to keep them in power. In this way, the Anglo-Persian Oil Company (the precursor to BP) was formed to develop the oil resources of what is now Iran, and similar deals were struck across Asia, the Middle East and Africa to support French, German and Russian interests.

After World War I, the balance of power in the Middle East shifted decisively to Britain and France, as these oil-hungry nations divided up the broken pieces of the Ottoman Empire. The US entered the region as well, winning concessions for its companies, and enlarged its already enormous influence in Latin America. As foreign companies maneuvered for advantage in the Middle East, one notable exception was the newly created state of Saudi Arabia, which was given a remarkable degree of independence, ironically because its oil prospects didn’t appear that promising at first, Fig. 1.

Rebellion. The first major move against the domination of foreign oil companies occurred halfway around the world, in Latin America. Yacimientos Petrolíferos Fiscales (YPF) was formed in 1922 in Argentina, and was the first fully state-owned oil company. (CFP, in France, was created two years later.) Argentina’s example was followed by Bolivia, which formed YPFB, and then Uruguay with ANCAP. The Mexican president José Cárdenas ordered the creation of Petroleos Mexicanos (Pemex) in 1938, and in the process expropriated the assets of the foreign oil companies. Brazil entered the NOC game in the early 1950s with Petrobras.

Fig. 2. The UAE depends heavily on natural gas for electrical and industrial uses. The flaring of associated gas, a common practice in the past, is being phased out except for emergencies.

It was the 1970s, however, that saw the greatest move toward nationalization of petroleum, not only upstream but, increasingly, downstream as well, as a series of price shocks underlined oil’s role as a strategic commodity. NOCs were formed in almost all oil-exporting countries. In the developing world, the NOCs were expected to fulfill a double role, profitably exploiting oil reserves (behaving like IOCs, in other words) and also furthering the policy and social goals of the government. As long as prices stayed high and the NOCs were flush with cash, they were able to accomplish this, for the most part.

The oil price collapse of the mid-1980s led to serious reassessment of the national oil companies, their organization and practices. Partial or complete privatization of NOCs became common, and the emphasis shifted to running them efficiently. Nevertheless, NOCs remain the dominant force in world petroleum, and as they begin to roam farther and farther afield, the differences between NOCs and IOCs become less obvious.

MIDDLE EAST

The Abu Dhabi National Oil Company (ADNOC) is the NOC of the United Arab Emirates (UAE). In terms of oil reserves, it is the fourth-largest oil company in the world, with an EIA estimate of 97.8 billion bbl and proven gas reserves of 215 Tcf. The company is fully integrated, with 14 subsidiaries in the upstream, midstream and downstream sectors.

As the UAE has the world’s seventh-largest reserves of natural gas, ADNOC has been developing its abundant gas fields both onshore and offshore, Fig. 2. Natural gas is exported as LNG, utilized for local electricity production and for other industries, and is also used for reinjection to improve production of the more valuable oil and condensate. The UAE also imports natural gas via pipeline from Qatar, and data indicates that it became a net importer in 2008. ADNOC recently announced that it will convert over 500 government vehicles and taxis to run on compressed natural gas (CNG).

In 2009, the UAE produced 1.865 Tcf of natural gas, or 5.1 Bcfd. Despite the country’s large natural gas reserves, high capital costs and high sulfur content remained problems limiting development. Abu Dhabi Gas Industries Ltd. (GASCO), a consortium of ADNOC, Shell, Total and Portugal’s Partex, is responsible for the processing of associated and dry onshore natural gas production.

In April 2010, ConocoPhillips withdrew from the ultra-sour Shah gas field. The sulfur content of the gas is so high that sophisticated technology will be required to remove it. The project was planned to produce 1 Bcfd plus associated liquids and sulfur and is supposed to start production in the third quarter of 2014. The government is reportedly spending over $1 billion for high-technology facilities to extract granulated sulfur fit for export from the ultra-sour gas.

Saudi Aramco. As the world’s largest integrated oil and gas company, Saudi Aramco took in nearly $183 billion in gross revenue in 2009. The company exploits the world’s largest oil reserves, around 267 billion bbl. According to EIA statistics, Saudi Aramco’s 2010 production came in at 10.52 million bpd of oil, leaving all other companies in the dust. So far in 2011, output has been somewhat lower. Aramco reduced production to 8.29 million bpd in March, although it produced 9.13 million bpd in February to make up for the shortfall left by Libya, which is embroiled in civil war.

Saudi Arabia must produce at least 9 million bpd of crude for the next several years and is considering boosting output to meet demand, according to Petroleum Intelligence Weekly, citing Saudi sources. Rising demand led by growth in Asia and the Middle East has exceeded Aramco’s expectations.

While the company has gone from strong to stronger over the years, its policies of strict secrecy in reserves data and its “take our word for it” approach has left much room for speculation about how long the largest producer can maintain its level of output, especially considering that the greatest share of those reserves is in one giant oil field, Ghawar, which alone accounts for over 5 million bpd. The amount of remaining producible reserves has been the source of vigorous debate, to put it blandly.

The Saudi government has vigorously pursued a policy of reducing dependence on outside expertise. This  “Saudization” has resulted in a staff that is reportedly 85% Saudi, with highly trained Saudi employees, management and professional staff. Saudis also hold most Aramco’s top management positions.

Upstream, Saudi Aramco has entered into four joint ventures with a variety of international partners, Royal Dutch Shell, Russia’s Lukoil, the Chinese NOC Sinopec, Italy’s Eni and the Spanish-Argentine company Repsol YPF, to explore for and produce non-associated gas for the domestic market. These joint ventures operate in various parts of the Rub' al-Khali or “Empty Quarter” (an enormous desert encompassing the southern third of the Arabian Peninsula).

KPC. Kuwait Petroleum Corporation, whose subsidiaries include the upstream Kuwait Oil Company (KOC) and downstream Kuwait National Petroleum Company (KNPC), holds fifth place for oil reserves, with a proven 104 billion bbl. This has allowed the small country to become OPEC’s fourth-largest exporter of oil. KPC’s production of 2.45 million bpd puts it in the top five NOCs.

To help compensate for declines at the mature Burgan field, in 1997 Kuwait’s Supreme Petroleum Council authorized Project Kuwait, a $7 billion, 25-year plan to increase the nation’s oil output, with the help of international oil companies. In particular, Kuwait aimed to increase output at five of its northern oil fields—Abdali, Bahra, Ratqa, Raudhatain and Sabriya—from 650,000 bpd to 900,000 bpd. KPC lacked the technical expertise to accomplish that objective, and therefore sought the assistance of the IOCs. KPC had tried, before the 1990 invasion by Iraq, to increase oil output to more than 2 million bpd, but it encountered serious technical challenges. Local expertise was only sufficient to produce the “easy oil,” which Kuwait has been producing since the nationalization of the country’s oil industry in 1975.

Fig. 3. For the past two years, the bulk of cross-border M&A activity has come from Asian NOCs. The goal has been capture of long-term resources.

Unfortunately, the project ground to a halt due to disagreements between the Kuwaiti Parliament and the ruling Al-Sabah family. After Kuwait failed to renew agreements with IOCs such as BP and Chevron, serious questions about the country’s ability to sustain production have been raised.

NIOC. The National Iranian Oil Company boasts the world’s third-largest oil reserves and second-largest gas reserves. The EIA estimates Iranian total production at about 4.03 million bpd. NIOC has been hampered by international sanctions over Iran’s nuclear program, making infrastructure improvements and project developments difficult to achieve.

Despite having its hands full maintaining its older oil fields, NIOC has ventured offshore in the Caspian Sea, and expects to finish drilling its first exploration well there in March 2012. Iran reportedly spent more than $500 million to construct and install the semisubmersible Amir-Kabir and supporting elements. NIOC is scurrying to catch up with other Caspian nations and their IOC partners, which have gotten a head start in the extremely promising region.

ASIA

The Chinese NOCs, together with Korea’s KNOC and Thailand’s PTTEP, have focused resources in foreign mergers and acquisitions, Fig. 3. According to Wood Mackenzie, they invested $35 billion in overseas M&A activity in 2010, Table 1. NOCs, and the Chinese NOCs in particular, have the strategic imperative and the financial muscle to significantly step up M&A activity. Last year saw the Chinese NOCs encroach further into IOC strongholds, most notably US shale gas, Canadian oil sands and deepwater Brazil.  Implicit in that was an increased willingness to apportion significant value to long-term, undeveloped resources, not just to proved reserves and production, as had tended to be the case in the past.

CNPC/PetroChina.  China’s largest oil company continues to punch well below its weight in the M&A market.  It announced just one deal in 2010 (PetroChina’s $1.6 billion acquisition of a 50% stake in Arrow Energy, alongside Shell), and is yet to make an acquisition of over $2 billion.  The company certainly has the financial strength to pursue major M&A opportunities.

Despite relative inactivity with regard to mergers, CNPC has ventured abroad, finding footholds in North and South America and in other regions.  Recently, the Chinese NOC signed a joint-venture agreement with Encana, Canada’s largest natural gas producer, to develop the Canadian company’s shale gas properties in northern British Columbia. CNPC and Encana also signed a cooperation agreement for the Chinese company to acquire a 50% equity in Encana’s 1.3 million acres of Cutbank Ridge assets in British Columbia and Alberta.

CNOOC.  Despite a notable step-up in M&A spending in 2010, CNOOC retains the financial capacity to pursue further deals.  Wood Mackenzie estimates that the company will generate around $10 billion in cash flow over the next three years (after interest, exploration, tax and dividend costs). 

Sinopec.  Net 2010 M&A spending of $11.4 billion pushed Sinopec’s cost of acquisitions for 2008–2010 to $23 billion, making it easily the biggest spender among the NOCs. The company has acquired strategically important positions in West Africa, Kurdistan, the Canadian oil sands, deepwater Brazil and Argentina.  Unlike the other Chinese NOCs, Sinopec tends to make acquisitions at the group level (Sinopec International), rather than at traded subsidiary level (Sinopec Corp). In Brazil, recently Petrobras signed a technology cooperation agreement with Sinopec to encourage exchange of knowledge in geophysics, geology and petroleum engineering.

KNOC.  Korea’s state oil company has a production target of 300,000 bpd of oil by 2012, but is currently on course to deliver only around 135,000 bpd.  Thus, despite making five major acquisitions since the beginning of 2008, the company remains short of its target.  More acquisitions are likely. Although Korea National Oil Corp.’s recent acquisitions were geographically widespread—UK, US, Canada, Peru and Kazaksthan—so far it has focused on conventional onshore or shallow water assets.

ONGC. Oil and Natural Gas Corporation is India’s premier NOC. It has been engaged in exploration and production since 1956, and has grown dramatically in its 55 years. It is now the No. 1 E&P company in the world in terms of financial performance and 18th among global energy companies, according to the Platts Top 250 ranking in 2010. This is the highest ranking ever for ONGC, placing it ahead of global leaders like Conoco-Phillips, Statoil, CNOOC and BG.

ONGC has also been the most profitable company in India for the past few years, and is second in market capitalization. The company has discovered in-place hydrocarbons equivalent to over 6.5 billion metric tons of oil, and has the largest reserve base and largest acreage holding. It commands recoverable reserves of 1 billion metric tons of oil equivalent, and boasts daily production of 1 million bpd.

In April, ONGC Videsh Ltd. (OVL), the wholly-owned overseas arm of ONGC, signed definitive agreements for acquisition of a 25% participating interest in the Satpayev exploration block with KazMunaiGas—the national oil company of Kazakhstan. This represents OVL’s first entry into Kazakhstan. Today, OVL participates in 33 oil and gas projects in 14 countries, and during fiscal year ended March 31 it had achieved its highest production of 9.434 million tons of oil equivalent.

Oil India. The country’s second-largest NOC, Oil India was incorporated in 1959 as a joint-venture private limited company between the Indian government and the UK’s Burmah Oil Company. It took its present form in 1981 when it became a wholly owned government company. The company’s predecessor was the first to drill an oil well in Asia, in Digboi, Assam.

Oil India’s exploration and production activities are primarily confined to Assam and other northeastern states in India. It is also operating in the state of Rajasthan in onshore areas of Ganga Valley and Mahanadi, and has participating interest in some blocks in Mahanadi offshore, Mumbai deep water and Krishna Godavari deep water, allotted during New Exploration Licensing Policy (NELP) bids.

Petrobangla. When Bangladesh was part of Pakistan, the exploration activities there were the responsibility of Pakistani state oil company OGDCL, which laid the groundwork with its geological and geophysical surveys. When Bangladesh gained independence in 1971, OGDCL’s operations in Bangladesh were reorganized under a new company called Bangladesh Mineral Oil and Gas Corp. (Petrobangla). In 1974, the government enacted the Bangladesh Petroleum Act to facilitate and encourage international participation under production sharing contracts.

The Bangladeshi government is now encouraging international companies to explore new gas fields and develop the existing ones. Recently, Petrobangla signed a preliminary agreement with ConocoPhillips for exploration in the Bay of Bengal, toward which ConocoPhillips has pledged to invest $111 million. It also has a memorandum of understanding with JSC Gazprom. According to Petrobangla Chairman Hussain Mansur, Gazprom will drill at least 10 state-owned gas wells in Bangladesh and develop those in an effort to boost output from some aging gas fields.

AFRICA

Since it was founded in 1977, Nigerian National Petroleum Corp. (NNPC) has struggled to maintain high production levels despite conflict and guerilla activity in the Niger Delta region. Production is currently about 2.17 million bpd; however, the EIA contends that this would be significantly higher had it not been for persistent attacks on infrastructure, resulting in shut-in production and forcing foreign companies to declare force majeure on oil shipments. Over 50% of Nigeria’s crude exports go to the US. NNPC manages the existing JVs in the country with partners Shell (the largest producer), ExxonMobil, Nigaz (a JV between NNPC and Gazprom), Saipem, Chevron, Total and Agip.

These multinational E&P companies operate predominantly onshore in the Niger Delta, in coastal offshore areas and more recently in deep water. As in many other developing countries, the IOCs in Nigeria operate under a concession system, with NNPC as concessionaire and the IOCs as operators.

The IOCs operate in partnership with NNPC under joint operating agreements (JOAs) or production sharing contracts (PSCs). Others, especially the indigenous oil companies (such as Oando and South Atlantic Petroleum, or Sapetro), operate in partnership with IOCs under sole risk or as independents.

Sonatrach. Algeria’s national oil company controls the third largest oil reserves in Africa. Algeria’s Saharan Blend sweet oil (45°API, 0.1% sulfur) is high quality and in demand in Europe because of the EU’s strict limits on sulfur content.

Sonatrach is the 11th-largest oil consortium in the world and operates Algeria’s largest oil field, Hassi Messaoud, which produces about 350,000 bpd. The company also operates Hassi R'Mel field, which produces about 180,000 bpd of crude.

The NOC was founded in December 1963, and Algeria nationalized all French oil and gas interests beginning late in 1971. The concession system was replaced by Algerian ownership of a 51% share in the French petroleum companies. All foreign oil companies except Total subsequently left the country.

Sonatrach (51%), with partners Total (47%) and Partex (2%), is developing the Ahnet gas project, covering 17,358 sq km in southwestern Algeria. Twelve gas formations have already been discovered. The consortium will invest $1.5–$2 billion in the Ahnet gas permit by 2014, according to Algeria’s energy ministry. The Ahnet contract area was allocated in a licensing round in 2009 in which contracts were also awarded to two consortia led, respectively, by Repsol and CNOOC. First gas is scheduled for 2015.

The same area of the country is also the location of the Timimoun project, operated by a consortium with Sonatrach, Total and Cepsa.

WESTERN HEMISPHERE

The Mexican NOC Petróleos Mexicanos is the fourth largest state-owned company in the world, with a total asset value of $415.75 billion. As the most lucrative enterprise in Mexico, the government depends on it for 40% of the federal budget. Pemex pays out over 60% of its revenue in royalties and taxes. The majority of its shares are not publicly listed and are controlled by the government.

The company is one of the largest examples of social goals trumping business goals. Almost from its creation, the company borrowed heavily, and Pemex’s debt increased from $76 million in 1952 to over $50 billion by the end of 2008. With a labor force of more than 140,000, the company is widely considered bloated and inefficient. Worse, it has not been able to stem the decline in Mexico’s production.

The story of Pemex production is closely tied to one field, the Cantarell complex, in the Bay of Campeche. Discovered in 1976, the field peaked in 2003 at 2.1 million bpd and then began a steady period of decline. A major nitrogen injection program undertaken in 2000 reversed the trend for a while, but the field fell below 1 million bpd in 2009, and at the end of last year was producing under 500,000 bpd, putting it in second place to the offshore Ku-Maloob-Zaap complex, discovered in 1979. Ku-Maloob-Zaap is expected to peak this year at about 800,000 bpd, not nearly enough to offset the sharp decline from Cantarell.

Mexico’s production has fallen by about 1 million bpd since 2004, to about 2.5 million bpd today (of which about 1.1 million bpd is exported to the US). The country may become a net importer by 2020.

A strenuous effort to develop Chicontepec, a heavy oil field northeast of Mexico City, has fallen short of expectations. In 2006, the government announced that Pemex would invest $37.5 billion over the next 20 years in Chicontepec, with a goal of increasing output to 1 million bpd by 2010. Pemex hired Schlumberger, Baker Hughes, Halliburton, Tecpetrol and Weatherford to run five field labs to determine the most productive techniques before expanding drilling at Chicontepec. In 2008, a contract for 500 new wells was offered. However, the field was producing only 46,000 bpd at the end of 2010. Citing the disappointing results, Pemex cut the 2010 budget for its $11.1 billion Chicontepec field development by 22% and ramped up spending at Cantarell.

Political reforms, although late in coming, may help. Changes to Mexico’s oil laws in 2008 allowed it to hire foreign companies. Previously, Pemex was forbidden by law to enter into profit-sharing agreements with IOCs. Pemex hopes to make deals with majors ExxonMobil, Royal Dutch Shell and Chevron to help develop reserves.

PDVSA. The Venezuelan state-owned petroleum company, Petroleos de Venezuela, was formed in 1976 with the nationalization of the 16 private oil companies that were  active in the country under the old concession system. This resulted in three fully integrated and state-owned operating companies under the oversight of a holding company.

Management was comprised of experienced staff from the former private concessionaires. From 1976 to 1999, the company philosophy of PDVSA revolved around efficiency and profit. The funds generated went to the national budget in a process that was admirably transparent, and oil production remained steady while reserves of both oil and gas increased significantly.

This all changed with the ascension of Hugo Chavez to the presidency in 1999. Chavez took over political control of the company and transformed it into a tool for the promotion and benefit of his regime. Decisions ceased to be made for business reasons, and management was hired and fired based on ideology and loyalty. By 2010, some 800,000 bpd of production capacity had been lost. High oil prices have allowed the money to continue to flow in, but these funds were not reinvested into the infrastructure, which has suffered greatly as a result.

PDVSA has lost the advantages of talented, autonomous management and foreign expertise. It has, however, formed partnerships to try and stem the erosion of production from its Orinoco heavy oil belt. It formed Petrozumano, a joint venture with China’s CNPC. PDVSA holds 60% of the new company, with CNPC controlling the remaining 40%. The JV is slated to explore for oil and gas in a 428-sq-km area in Anzoategui state for a term of 25 years. Similarly, PDVSA controls another consortium, called Venrus, with Russia’s Gazprom, Rosneft, TNK-BP, Surgutneftegaz and Lukoil, to develop two blocks in the Carabobo area of the Orinoco.

The Venezuela NOC’s largest deal to date is with the Italian energy company Eni. In accordance with its policy of “oil sovereignty,” PDVSA retains 60% while Eni will control the remaining 40% of the new company, Petrojunin (or Empressa Mixta). The consortium is reportedly investing $8 billion to extract oil from the Junin-5 block of the Orinoco belt. The companies expect production to begin at 70,000 bpd in 2012 and increase to 240,000 bpd once the project is fully developed.

Fig. 4. The Petrobras P-57, a super platform with capacity to extract 180,000 bpd, has begun oil production at Parque das Baleias field in the north Campos basin offshore Brazil.

Fig. 5. Sinopec and Petrobras signed a joint venture agreement for exploring blocks off the coast of northern Brazil, in the Pará-Maranhão basin.

Petrobras. The Brazilian state-owned oil and gas company was formed in 1954. As in the case of Pemex, politicization was a powerful influence during the 1970s and 1980s due in part to an ultra-nationalistic environment in the country. By the mid-1980s, Petrobras was bloated and poorly managed, and Brazil was a net importer of oil.

Today, Petrobras is an energy goliath, set to make Brazil a net exporter of petroleum. Also, it has become an international company that operates successfully in more than 25 countries. Petrobras has accomplished this by dramatically changing its corporate structure and culture. It went partially public, selling shares on the open financial markets. The Brazilian government owns 54% of Petrobras shares directly, and Brazil’s sovereign wealth fund and the Brazilian Development Bank each own 5%, bringing the government’s effective ownership to 64%. Having to answer to shareholders has been a major incentive to accountability and transparency.

In the 1950s, a team of Brazilian and American geologists concluded that Brazil’s prospects for large oil discoveries were slim. This was at a time when deep water was not considered a realistic province for exploration. Everything changed with the exploration of the Campos basin. Several offshore discoveries were made beginning in 1974, at first in shallower water, then deeper and deeper, Fig. 4.

Petrobras has about 40 fields in the Campos basin, accounting for about 90% of Brazil's crude production. In recent years, the company has made a series of major oil discoveries in the Campos and Santos basins. These discoveries were made by exploring deliberately in areas adjacent to previous oil finds. This cuts costs, because the company already has the production, storage and offloading infrastructure in place.  Most intriguing was the discovery that the formations have two giant oil-bearing zones, one above the salt layer (postsalt) and a larger one below (presalt). Petrobras recently made Brazil’s largest oil discoveries in the presalt layer located offshore the states of Santa Catarina and Espírito Santo, where major volumes of light oil were found. The oil is of high quality, with a gravity of 28.5°API and low sulfur content.

In 2010, Petrobras finalized a joint venture agreement with China’s Sinopec to explore blocks off the coast of northern Brazil. The blocks, BM-PAMA-3 and BM-PAMA-3, lie in the northwestern part of the Pará-Maranhão basin, Fig. 5.

CONCLUSION

Comparison of these three Latin American companies is instructive. Each company’s course is directly related to the role it plays in its respective country. Pemex is a symbol of Mexican pride and nationalism. The company’s management has limited autonomy in making decisions, and the state severely limits the participation of private companies in many aspects of the industry, although this situation is improving. In Venezuela, PDVSA serves as a political tool at the service of an autocratic ruler, with little consideration given to good business practices. In contrast, Brazil’s Petrobras is a prosperous, growing commercial company.

Although all three of these companies are influenced by national policies and goals, Petrobras uses professional management practices, makes decisions that serve a broad, long-term state energy policy, and is fully open to participation by the private sector. This is the difference between success and failure. 

ACKNOWLEDGMENT

World Oil Contributing Editor Raj Kanwar and analysts at Wood Mackenzie contributed to this article.