South America’s oil producers luring multinational E&P companies

The old adage that money has no ideology proves true for the region’s oil economies.  

Dayse Abrantes, Contributing Editor, Latin America

Brazil, the largest nation in South America, has dazzled the world oil industry with a string of massive pre-salt light oil discoveries. Petrobras is overcoming ultradeep waters and technological hurdles to produce oil and gas below thick layers of salt and is working to become the fifth-largest integrated energy company in the world.

Brazil’s President Luiz Inacio Lula da Silva has worried Big Oil by sending four draft bills to Congress to change pre-salt oil regulations to increase governmental control over the oil wealth. According to him, the resources should also be used for investments in infrastructure, R&D, education and a better public health system.

Nevertheless, international oil companies (IOCs) are eager to participate even more in Brazil’s pre-salt bonanza and some continue to invest in Venezuela, an OPEC member and the continent’s largest producer of petroleum.

Venezuela’s government control over the petroleum sector, a string of nationalizations and financial difficulties (due to the slump in oil prices and decreased oil production) did not discourage some IOCs or national oil companies (NOCs) from participating.

President Hugo Chavez’s socialist policies did not hamper Spain’s Repsol, now laughing all the way to the bank with the prospects of profits from a recent mammoth natural gas discovery.

The story repeats itself in Bolivia, where Repsol plans to invest $1.5 billion in natural gas blocks. Bolivia nationalized its hydrocarbon sector in 2006 but did not scare away all multinational oil companies.

This year, socialist President Evo Morales was praised by the International Monetary Fund (IMF) for administrating the macro-economy in a rather reasonable way. Morales, the first indigenous president of a South American country, maintains close relations with Venezuela’s Chavez. However, since money has no ideology and Bolivia is one of the poorest countries in Latin America, Bolivia welcomes foreign investments under its own strict conditions.

Mexico, which has been ruled by conservative governments since 2000, has been unable to break the gridlock over the constitutional monopoly of state-owned oil company Pemex that keeps IOCs at bay. Oil reserves are declining at an alarming rate, especially at Cantarell, Mexico’s largest oil field.

Pemex lacks capital, expertise and technology to explore promising prospects in the Gulf’s ultradeep waters, where estimates point to some 50 billion bbl of reserves. To offset the decline in production and attract IOCs and NOCs, the government is putting together risk contracts that do not violate the legal framework of Mexico’s Constitution.

A GEOPOLITICAL ANGLE TO PRE-SALT FINDS

President Lula has a very broad view of what it takes for a country to achieve geopolitical importance. Finding and producing oil and gas some 300 km off the coast at depths of up to 7,000 m from the water line and under the salt layer could vault Brazil to the select club of the top five crude producers, but should not be considered a sufficient criterion to transform Brazil into a geopolitical heavyweight, he says.

For Lula, every citizen should benefit from the pre-salt bonanza, and this would better define the country’s international importance. The wealth must be invested in education, technology, upgrading infrastructure and public health, he says. Lula is hugely popular, with approval ratings around 80%.

A former shoeshine boy and union leader, Lula is a pragmatist, neither a leftist nor right wing. According to research undertaken by some universities and by the Brazilian Institute of Geography and Statistics (IBGE), Brazil recently improved scores in its fight against poverty. For many people, the fact that Lula put social programs at the top of his agenda during his campaign and since his election has clearly contributed to this success.

Also, after decades as the largest emerging market debtor, Brazil became a net foreign creditor for the first time in January 2008. By mid-2008, both Fitch ratings and S&P had elevated the classification of Brazilian debt from speculative to investment grade.

In several interviews, Lula warned about the dangers of the “oil curse” that afflicts so many countries whose economies are mainly petroleum based. Thus, he favors production of refined products instead of the export of crude to set the basis of economic expansion, diversify the economy even more and create an estimated one million jobs per year.

Stiffer oil regulations. In the draft bills sent to Congress last August, besides proposing changes in the present concession model to a production sharing model (thus giving the state more control over crude reserves), the Brazilian government proposed the creation of a fund to finance health and education projects.

The production sharing system will apply to new contracts signed for fields in about 72% of the currently interpreted pre-salt area. Petrobras will be the operator of all new contracts for exploration and production of the pre-salt areas and of other areas considered strategic by the government.

The Brazilian government can either exclusively hire Petrobras or conduct public bids with the free participation of any company. The winner of the bid will be the company that offers the highest percentage of “profit oil” for the Brazilian government. In this case, Petrobras will have to offer the same percentage offered by the winning bidder to the state in the proportion of its minimum participation.

Petrobras will be entitled to a minimum participation of 30% of the capital stake in each project. In areas in which Petrobras has exclusivity, a percentage of “profit oil” will also be paid to the Brazilian government.

Previously awarded contracts, which involve roughly 28% of the pre-salt region, will remain unchanged, say Lula and his ministers.

The new model also includes the creation of a public company to represent the interests of the Brazilian government in the production sharing contracts. The new company (Petrosal) will not conduct upstream activities or engage in investments, but it will participate in operational committees that will define consortium activities with voting rights and veto powers.

At present, heated discussions are taking place among congressmen on behalf of producing states and non-producing states regarding the distribution of royalties. Although there are many conflicting amendments to be voted on, political analysts feel that the draft bills changing the petroleum regulations will pass due to the majority the government enjoys through a coalition with a centrist party.

Congress is expected to take amendments to voting sessions by the beginning of 2010, and the most optimistic estimate that a new round of auctions by the National Petroleum and Biofuels Agency (ANP) will take place by the end of the first semester, after the Senate debates and votes on the draft bills.

Lula’s draft bills and the linkage of oil wealth with tackling social problems is making some IOCs nervous. However, in all opinion polls, Lula’s chosen successor, Civilian Chief of Staff Dilma Roussef, a former mines and energy minister and Petrobras chairman, is trailing way behind the probable opposition candidate, conservative São Paulo State Governor José Serra. But everyone knows that elections can be a Pandora’s box, and it is still far away, in October 2010.

Official and non-official recoverable volumes. Petrobras expects to invest $111.4 billion developing production in the pre-salt through 2020: $98.8 billion in the Santos Basin and $12.6 billion in Espírito Santo. According to the company’s estimates, by 2013 the pre-salt will be producing an average 219,000 bpd of oil.

At present, Brazil has proven reserves of 14.4 billion bbl of oil equivalent (boe), and some geologists estimate that there is probably 50–100 billion boe in the pre-salt areas.

November 2007 marked the breakthrough of pre-salt discoveries with Tupi Field in the BM-S-11 Block (S for Santos Basin). Recoverable volumes estimated by Petrobras are from 5 to 8 billion boe.

Major discoveries in the pre-salt are spread along 800 km off the coast of Santa Catarina, São Paulo, Rio de Janeiro and Espírito Santo states. The oil there is of good quality (around 30°API) and is nestled in reservoirs at depths of 5,000–7,000 m from the water line.

Logistics are another challenge. Tupi, in the Santos Basin off São Paulo state, is nearly 300 km off the coast, while the Campos Basin’s producer fields off Rio de Janeiro are up to 150 km away from shore, Fig. 1.

Fig. 1. Location map of the Santos and Campos Basins.

Other Santos Basin pre-salt reservoirs—such as Jupiter (BM-S-24 Block); Carioca and Iguaçu (in the BM-S-9 Block, where Petrobras recently announced a new discovery—Abaré); Bem-Te-Vi (BM-S-8); Parati (BM-S-10); Caramba (BM-S-21); Azulão and Guarani (BM-S-22); and Iracema (BM-S-11)—are all in their assessment phases.

Petrobras announced that the two formation tests for Well 4-RJS-647 (4-BRSA-711-RJS), located in the Tupi assessment area known as Iracema, proved the high productivity of the pre-salt carbonate reservoirs. The Iracema well was drilled by Seadrill’s West Taurus semisubmersible.

In each of the two tests, the measured flow was 5,500 bpd of light oil (about 32°API), limited to the capacity of the equipment used in the testing phase. The well’s initial production is estimated at up to 50,000 bpd of oil.

Iracema was drilled to a depth of 5,000 m, 33 km from the initial Tupi well, and completed in September 2009. It is located in 2,210 m water depth. With the drilling of new wells, the consortium, formed by Petrobras (65%, operator), the BG Group (25%) and Galp (10%), expects to declare Iracema commercial until December 2010.

Also in the assessment phase is Guará Field (BM-S-9 Block), discovered last September, but non-official estimates point to 1.1–2 billion bbl of recoverable volumes. Also unofficial is the 1.5–2 billion-bbl estimate for a cluster of finds called Parque das Baleias (Whales Park) discovered off the coast of Espírito Santo state in the north portion of the Campos Basin.

Parque das Baleias presents an additional challenge because its warm waters are a meeting place for whales. The estimate  includes reserviors in the Baleia Franca, Baleia Azul and Jubarte post-salt fields. In Jubarte, a pre-salt well started Brazil’s first pre-salt oil production (15,000 bpd) on September 2008 (see World Oil, January 2009, p. 70). Parque de Baleias post-salt production is taking place in Baleia Anã, Cachalote, Nautilus, Mangangá and Argonauta Fields.

The Iara reservoir, discovered near the BM-S-11 Block in October 2008, holds 3–4 billion boe. Around 40 Tcf of gas is expected to be recovered from the Tupi, Iara and Guará discoveries, a spokesperson for the BG Group said. BG also holds interests in Parati, Carioca and Iguaçu Fields.

Other major companies with interests in Santos pre-salt areas are: Partex, Petrogal, Amerada Hess, Shell and Repsol YPF. Repsol has holdings in Brazil’s offshore Santos, Campos and Espírito Santo Basins. “In 2010, I believe we will invest in Brazil $380 million, $400 million,” CEO Antonio Brufau told reporters in Rio de Janeiro. He added,“For the next three or four years, it’s just in exploration. When we get to developing the fields, we will need billions of dollars.” He said Repsol’s Brazilian investments over the next 10–12 years could reach $14 billion.

Oil to meet strict specifications. Tupi is expected by Petrobras to produce 100,000 bpd of oil and 177 MMcfd of gas in 2010, surpass the 1 million-bpd mark by 2017 and top out at 1.8 million bpd in 2020, nearly doubling Brazil’s current production.

Petrobras has been performing an extended well test (EWT) in Well 1-RJS-646 at Tupi since last May with the Cidade de São Vicente FPSO, a 140,000-dwt, Suzemax-category ship anchored at 2,140 m water depth.

The EWT allows technicians to acquire knowledge about production conditions, the behavior of the reservoir in long-term production and the movement or draining of the fluids during production. In this test, the well geometry is also being analyzed. In the Santos Basin’s pre-salt region, among other characteristics, the reservoirs are in carbonate rocks of microbial origin, unlike the sandy turbidite formations found in the Campos Basin, which are already known by Petrobras.

Tupi’s oil is transported 290 km to the coast by relief ships in 264,000-bbl loads and refined at Petrobras’ Henrique Lage refinery in São José dos Campos, São Paulo state. According to the Bureau of Mines characterization factor, its API gravity is 29.2°.

Tupi’s oil is rated as paraffinic, and the sulfur level is low and will meet increasingly strict specifications for all refined products, particularly for naphtha, diesel and propane for petrochemicals.

Until four years ago, most of the exploration activity in the Santos Basin was in shallow waters; now, higher product prices and the basin’s high-quality yield are proving ultradeep exploration to be a world-class risk opportunity.

Anadarko does it again in the pre-salt. In November 2009, US independent Anadarko Petroleum announced its second pre-salt discovery in the Campos Basin. The Wahoo-2 (also called Wahoo North) appraisal/exploration well in the BM-C-30 Block has encountered more than 90 ft of high-quality net oil pay in the same pre-salt interval as the original Wahoo discovery.

Drilled by the Deepwater Millennium drillship, the Wahoo-2 well is located 5 mi north of the previously announced Wahoo discovery, which encountered more than 195 ft of net pay with similar characteristics to the nearby Jubarte 1-ESS-103A well in Brazil’s first producing pre-salt field, operated by Petrobras.

“The Wahoo North well is confirming all of its objectives, and the early results from the cores and wireline logs ... indicate high-quality resources and reservoir rock,” said Bob Daniels, Anadarko’s Worldwide Exploration Vice President, in a statement. “We have approximately 2,000 ft left to drill before we reach TD to test a secondary exploration objective; nonetheless, our activities so far have confirmed that the main pay section in the original Wahoo discovery extends at least 5 mi to the north, and the hydrocarbon accumulation has been extended further down the structure.

“We believe the results to date increase the potential resources in the prospect area, and, from what we’ve seen so far, Wahoo has the characteristics necessary to potentially become our next mega project.”

Following the completion of drilling operations at Wahoo-2, Anadarko plans to move the drillship to the original Wahoo discovery well to conduct drillstem testing (DST), and then back to Wahoo-2 to conduct another DST in 2010.

Anadarko, through a wholly owned subsidiary, holds a 30% working interest and is the operator of BM-C-30. Devon Energy Corp. holds 25%, IBV Brasil Petróleo Limitada, a wholly owned subsidiary of Bharat PetroResources Limited and Videocon Industries, holds 25%, and SK Energy Co. holds the remaining 20%.

Also in the Campos Basin, in the adjacent BM-C-32 Block, Anadarko and partners are drilling the Itaipu prospect, where Anadarko holds a 33% working interest. The Itaipu well will test a pre-salt geologic feature similar to the adjacent Jubarte Field, estimated to hold up to 2 billion barrels of recoverable oil and currently producing about 18,000 bpd of 30°API light oil.

OGX: A young giant. Since its inception in June 2007, OGX Petróleo e Gás Participações SA has established a leading position in the Brazilian E&P sector by acquiring a large and diversified portfolio of high-potential exploration blocks. The new kid on the block is a giant independent company whose President Eike Batista, a college dropout, is Brazil’s richest person with a net worth of $7.5 billion, according to Forbes magazine.

In November 2007, OGX raised $1.3 billion in an equity private placement, providing capital to purchase concession rights in the Ninth Bidding Round held by the ANP. OGX acquired concession rights to 21 exploratory blocks in the Campos, Santos, Espírito Santo and Pará-Maranhão Basins, comprising a total area of 6,400 sq km (1.7 million acres). Thus, in terms of offshore exploratory acreage, OGX is now the largest Brazilian private oil and gas company.

In November 2009, OGX released the results of a report prepared by DeGolyer & MacNaughton (D&M) that certifies that OGX’s net risked prospective resources are 6.7 billion boe. D&M was also responsible for OGX’s first appraisal report in March 2008, which estimated 4.8 billion boe of net risked prospective resources with an average probability of success of 27% based primarily on 2D seismic data.

The company’s paper wealth increased dramatically in June 2008 when Batista listed OGX in one of Brazil’s largest-ever initial offerings, raising $3.9 billion.

Planning to pursue additional growth opportunities, OGX has entered into a farm-in agreement for a 50% participating interest in an exploration block in the Santos Basin, the 22nd concession, totaling 6,800 sq km.

In December 2009, OGX announced that it has identified an oil-bearing interval in the Aptian section of Well 1-OGX-2A-RJS, located in shallow waters of the southern Campos Basin in the BM-C-41 Block. OGX holds a 100% working interest in the block.

The well is about 77 km off the coast of Rio de Janeiro state at a water depth of about 130 m. The rig Ocean Ambassador, provided by Diamond Offshore, initiated drilling activities in October.

According to the company, the oil shows in the cuttings and log analysis indicated an oil column of 170 m and net pay around 50 m. The reservoirs are conglomerates, sandstones and carbonates, with up to 20% porosity. The drilling of OGX-2A is still in progress, aiming at additional targets.

“The presence of these oil-bearing reservoirs in the Aptian section confirmed our model for this area,” said Paulo Mendonça, OGX’s general executive officer, in a statement.

“Our results so far give us further confidence that we have found a new oil province in the southern part of the Campos Basin,” added Mendonça, a former top Petrobras executive.

OGX hasn’t provided volume estimates for discoveries in the well’s Aptian and Albian sections. It plans to drill 79 wells by 2013.

PDVSA’S DECLINING REVENUES

A recent press release from Venezuelan state-owned Petroleos de Venezuela SA (PDVSA) said net income in the first half of 2009 fell by 67% to $3.17 billion due to slightly lower output, lower sales volumes and a steep decline in oil prices. “For the January–June 2009 period, the average export price for the Venezuelan basket was $47.33 per barrel, which represents a decline of $48.79 compared to June 30, 2008.”

These factors caused revenues to fall by 52%: “In the six months that ended on June 30, 2009, revenue totaled $32.5 billion, a decline of $35.2 billion relative to the same period of 2008,” the statement read.

“The total consolidated net profit for the period was $3.17 billion, down by $6.37 billion compared to the same period of 2008.”

Meanwhile, output was affected by cuts agreed upon by OPEC in response to lower global demand: “Average crude production at the end of the first half came in at 3.1 billion bpd, down by 186,000 bpd from the first half of 2008.”

PDVSA’s revenues account for roughly 90% of the country’s export earnings and fund about half the national government’s budget, with the company’s contributions paying for health clinics for the poor and other social programs.

Perla: One of the largest 2009 finds worldwide. All things considered, Chavez’s ideological approach to the oil business has a good chance to survive this wave of bad financial news. Spain’s Repsol has confirmed in Venezuela its biggest-ever gas discovery and the largest find of its kind made in Venezuela.

The offshore field contains recoverable gas reserves of between 1 and 1.4 billion boe, enough to fulfill Spain’s gas demand for five years.

Repsol is the co-operator of the discovering consortium for the Cardón IV Block in a joint venture with Eni. Development of the block would require PDVSA acquisition of 35% of the consortium, while Repsol and Eni would maintain a 32.5% stake.

The Perla-1X well reached a total depth of 3,147 m in water 60 m deep, Fig. 2. During production tests, the well flowed 20 MMcfd of gas with 620 bbl of condensate per day, with the flowrate being constrained by rig equipment restrictions.

Fig. 2. Location map of huge natural gas find in Venezuela. Courtesy of Repsol.

Repsol YPF says that the Americas represent the most important region of continuous growth for the company.

According to the IHS oil and gas exploration information service, the Perla discovery is among the five largest hydrocarbon finds worldwide in 2009.

Applying SAGD in the Orinoco. “The Faja,” as the Orinoco belt is locally known, located in the southern part of the Eastern Venezuelan Basin, is a gigantic reservoir of 55,000 sq km, with estimated accumulations of 1.3 trillion bbl of oil in place. At present, the Orinoco heavy oil belt constitutes the biggest accumulation of heavy oil in the world.

Carabobo, previously named Cerro Negro, is one of four major areas within the Orinoco belt covering 112 sq mi and is located in the eastern segment, south of Monagas and Anzoátegui states.

Petromonagas, a joint venture of PDVSA and BP, studied the feasibility of increasing the oil recovery factor in Carabobo’s Morichal reservoirs by using a thermal numerical simulator with four different well configurations and 16 sensibility cases with steam-assisted gravity drainage (SAGD).

Vertical distances between injectors and production wells and the daily steam injection rate were varied to compare the production in a period of 20 years.

At the end of the study, presented during the Reservoir Characterization session of the AAPG 2009 International Conference and Exhibition in November in Rio de Janeiro, the companies concluded that it was feasible to implement a methodology using SAGD in a reservoir with typical properties of the Orinoco belt. Based on simulation, thermal processes recover much more than cold production processes, making SAGD an efficient technology to improve the recovery factor in heavy oil reservoirs.

Carabobo tender in February. A source at Venezuela’s oil ministry told World Oil that, after many delays, different terms for the upcoming Carabobo tender for seven blocks in the Orinoco heavy oil belt have finally been presented to interested companies.

Among the changes, a 60% tranche can now be paid in three parts within three years instead of all at once, and companies that acquire blocks will have to deposit a bonus payment ranging from $500 million to $1 billion to the government. The source said the government believes that these figures will not discourage companies.

Investments in the seven Carabobo blocks are expected to reach $30 billion for production of an additional 1.2 million bpd of heavy crude.

PDVSA will stay with a 60% stake in any joint venture resulting from the tender. In addition, JVs might also be required to finance at least 30% of PDVSA’s stake.

The following companies have shown interest in the tenders: Chevron; BP; Italy’s Eni; China’s CNPC and Sinopec; Portugal’s Galp; Japan’s Inpex, Jogmec and Mitsubishi; India’s ONGC; Petrobras; Malaysia’s Petronas; Royal Dutch Shell; StatoilHydro; Total and a consortium of Russian oil companies. The companies are evaluating the new terms, and bidding may start in February 2010.

The Russian National Oil Consortium signed a memorandum of understanding on cooperation for the exploration of oil reserves in the Orinoco belt. Closely following this agreement, Venezuela signed an agreement with China, also for development of its resources in the Orinoco belt. China has agreed to invest close to $16 billion over three years.

The Russian National Oil Consortium is comprised of TNK-BP, Rosneft, Lukoil, Gazprom Neft and Surgutneftegaz, and is likely to fund infrastructure investment worth $600 million initially. The Russian consortium will support the development of new blocks, along with the Junin-3 Block, Ayacucho-2 Block and Ayacucho-3 Block, which were being handled by Russian NOCs.

BOLIVIA INKS DEAL WITH REPSOL

Bolivia has an estimated 48 Tcf of natural gas, giving it the second-largest reserves in South America after Venezuela.

Repsol’s chairman, Antonio Brufau, and Bolivia’s President Evo Morales reached an agreement in La Paz in November to develop the onshore Caipipendi Block, Fig. 3.

Fig. 3. Bolivia’s President Evo Morales (left) and Repsol CEO Antonio Brufau in La Paz, Bolivia, after inking a major natural gas deal. Courtesy of Repsol.

According to the Repsol chief, Caipipendi, located in southern Bolivia in Tarija and Chuquisaca departments, contains resources of 3.7 Tcf. Repsol’s commitment is to carry out the development plan in the Caipipendi Block, which implies investments of up to $1.5 billion.

At a function to announce the investment, Brufau said the block’s gas production will rise sevenfold during the next five years to reach a daily output of 490 MMcf.

All the reservoirs in that area will be developed and exploited by a consortium of Repsol YPF Bolivia SA (37.5%, operator), BG (37.5%) and PAE E&P Bolivia (25%) in line with the conditions agreed upon with Yacimientos Petrolíferos Fiscales Bolivianos (YPFB), Bolivia’s national oil and gas company.

Repsol’s investments in the Caipipendi Block include Margarita and Huacaya Fields, which cover a surface area of 123,000 hectares, including five wells at depths between 4,000 and 8,000 m drilled by Repsol.

Margarita Field began producing in December 2004, following the construction of a gas treatment plant, and is currently producing 70 MMcfd.

During the event, Morales said Bolivia needs to progress beyond exporting natural gas to creating value-added products.

“Industrialization will ensure that Bolivia is no longer one of the most underdeveloped countries in the hemisphere and that it can lift itself up by its own bootstraps,” the president said.

Fiscal incentives for private companies? Also in November, Morales’ government created a company to promote and develop projects to process the Andean nation’s massive reserves of natural gas. Hydrocarbons and Energy Minister Oscar Coca said the goal of the new company, Empresa Boliviana de Industrializacion de Hidrocarburos, will be to “re-launch” the natural gas industrialization process, because “the efforts made up to now have been insufficient.”

“Bolivia has set itself the challenge that nationalization is not enough; the second step is industrialization,” Coca told reporters.

The government announced in June its plans to invest $80 million to build a petrochemical plant to produce fertilizers in the central province of Cochabamba as part of the gas industrialization effort.

A draft bill expected to reduce the tax load of companies exploring for gas is being prepared. Brazilian business newspaper O Valor reported that Bolivia might change the gas law following December’s presidential election, when Morales was reelected president for a second four-year term.

To industrialize the country, it is necessary to produce more gas, and YPFB has been meeting with private oil companies to exchange ideas for a new law that would create fiscal incentives to encourage new investments in gas fields, the paper reported.

Since 2004, Bolivia has been producing about 1.4 Bcfd. Around 10 years ago, 64 wells were drilled per year. At present this figure has dropped to four wells per year. “The government has realized that it cannot force companies to invest,” said Carlos Arze Vargas, a researcher who specializes in Bolivia’s energy industry.

According to YPFB, close to 1 Bcfd of Bolivia’s gas output goes to Brazil and 270 MMcfd is exported to Argentina.

MEXICO’S OIL OUTPUT DECLINING SHARPLY

Mexico’s President Felipe Calderón told the newspaper La Jornada that his country was among the hardest hit by the economic crisis due to its close ties with the US and because of the reduction of its petroleum production and the decline in crude oil prices, Fig. 4.

In fact, 80% of Mexico’s exports go to the US, and imports from the US are similar. Thus, Calderón said, “When the crisis started in the US, our country was the first affected. We are the country that most depends upon the US.”

The irony is that, while Mexico has a pro-market government, the Constitution bans private investments in hydrocarbons. Lacking investments, oil production from Petróleos Mexicanos (Pemex) averaged 2.61 million bpd in 2009, down 7% from 2008 and 22% from the 2004 peak.

Although Pemex budgeted $19 billion for deepwater exploration in 2009, no new large fields have been found and the company is $50 billion in debt. In 2008, Mexico’s Congress rejected a proposal from President Calderón to allow some foreign investment in oil exploration.

Mexico’s most pro-market party has been in power since 2000, yet little has been achieved, particularly in relation to Pemex. The government is also hampered by a legislature controlled by the opposition, but the more fundamental issues are the persistence of a generally nationalistic political tradition.

Risk contract to offset Cantarell decline. Since risk contracts do not violate the legal framework of Mexico’s Constitution, Pemex and the energy secretariat are preparing risk contracts that will be offered to oil companies—international and domestic—to accelerate the search for oil and gas. According to Mexico’s daily El Universal, the most important reason for the contracts is the rapidly declining output of Cantarell Field.

Cantarell represents a loss of $20.8 billion a year in tax revenue for the country or 2% of estimated gross domestic product for 2009, at November 2009 oil prices.

“The situation with what used to be Mexico’s main oil field is worrisome because, since 2005, we have seen its decline lead to a production drop of nearly 770,000 bpd,” an energy secretariat spokesperson was quoted as saying. Cantarell’s contribution to national production in 2005, when the output was 2.2 million bpd, represented 60% of the country’s output.

Legal experts say that a service contract between an NOC, as in Pemex’s case, and an IOC is often used in marginal fields, or even old producing fields where the NOC lacks capital, people and technology to maximize production. The NOC continues to own the block, any infrastructure and any resulting production.

There is, therefore, no technical change of ownership as far as the state or the NOC is concerned. The field, however, is taken over by the contractor as operator, often along with an additional exploratory area. The contractor is paid a negotiated fee per barrel of oil.