Via The Oil & Gas Journal, an in-depth comparison of Mexico’s Petroleos Mexicanos (Pemex), Venezuela’s Petroleos de Venezuela SA (PDVSA), and Brazil’s Petroleo Brasileiro SA (Petrobras), the most talked-about and likely the most influential National Oil Companies (NOCs) in the Western Hemisphere and three of the New Seven Sisters.  As the article notes:

“…Pemex and PDVSA are among the five largest suppliers of crude to the US. Petrobras has expanded around the world to meet the needs of its own huge market, the Western Hemisphere’s third largest. Its prolific presalt discoveries off Brazil have the potential to lift it into the top echelons of integrated companies.

The contrasting histories, conditions, and directions of Pemex, PDVSA, and Petrobras illustrate the wide range of strategies that NOCs follow in response to their unique combinations of competitive and political pressures—and the full range of successes and failures.

Pemex struggles

Pemex is sole producer of crude, natural gas, and petroleum products in Mexico and the country’s most important company. It is the biggest enterprise in Mexico, the biggest source of income for the Mexican government, and the third largest exporter of crude to the US, behind Canada and Saudi Arabia.

Once it was the model for other Latin American NOCs trying to develop their own resources. But Pemex’s crude production has fallen for years due to “steep decline rates from maturing oil fields (mainly Cantarell field), a lack of foreign investment, and a high tax burden on Pemex,” said analysts in the Houston office of Raymond James & Associates Inc. The decline is so bad, they said, “Mexico may become an oil importer within the next 5 years.”

Pemex’s reserve replacement rates rank near the bottom and its costs near the top among NOCs. Its development of gas reserves appears to be stalled. And it is in dire need of technology to explore ultradeep waters of the Gulf of Mexico and of a large infusion of money to fund exploration and development. Yet Mexico appears determined to maintain its constitutional ban on foreign ownership of natural resources.

“Mexico is effectively closed to foreign investment. This inhibits the interchange of differing geotechnical ideas and denies Mexico sufficient risk capital to fully exploit its oil and gas resource,” said Andrew B. Derman, partner and leader of international energy practice at Thompson & Knight LLP in Dallas. “Given Mexico’s proximity to the US, it could be one of the hottest oil and gas plays on the planet. One would think that Mexico would exploit its resources now when there is a demand. Mexico may discover that exploitation mañana is not nearly as profitable.”

Michael C. Lynch, president, Strategic Energy & Economic Research Inc., differs from the generally pessimistic consensus on Mexico. “I think Mexico will probably surprise many,” he said.

Lynch said, “[Pemex’s] first need has been capital; the government has a long tendency to starve them of money, and only recently has this been reversed. Mexican drilling activity is twice what it was a couple of years ago, and they have a lot of medium-sized fields that could make a serious contribution. (The decline in rigs rates has helped them, but the peso decline offset that somewhat). Deregulation and outside investment would certainly help, but capital is the main thing.”

Pemex production

At the start of this year, Pemex claimed proved reserves of 14.3 billion boe of oil and gas, including 10.2 billion boe developed. It also had 14.5 billion boe of probable reserves and 14.7 billion boe possible. Proved gas reserves were 17.6 tcf, including 11.5 tcf of associated gas. Proved, probable, and possible gas reserves totaled 60.4 tcf. The largest concentration of reserves is offshore, primarily in the Campeche basin, where tropical storms and hurricanes sometimes disrupt operations.

Pemex’s production dropped to 2.8 million b/d in 2008 from 3 million in 2007. Two thirds of its production is heavy Maya crude that averages 22° gravity and 3.5-4% sulfur content. Pemex retains its lighter crude for domestic consumption and exports Maya production to the US. Last year exports were down 16.8% to 1.4 million b/d of crude, with 1.2 million b/d going to the US.

From 2004-07, Mexico was the second-largest oil supplier to the US, but fell to third in 2008 behind Canada and Saudi Arabia. Proximity of the US market and the sophistication of US refineries will continue to attract most of Mexico’s oil exports, according to analysts at the US Energy Information Administration.

Production from Cantarell—once Mexico’s biggest oil field and among the international giants—slipped below 700,000 b/d in May from peak production of 2.1 million b/d in 2004.

“The death of Cantarell has been much discussed,” said oil analyst and investor Gregor Macdonald. However, he said, “What’s less recognized is that the toppling of Cantarell has absolutely shattered Mexico’s effort to halt the decline of oil exports.”

Ku Maloob Zaap (KMZ) adjacent to Cantarell in the Gulf of Campeche is the largest source of new production growth. It recently overtook Cantarell as Mexico’s biggest producer, with record output of 814,000 b/d in April. The KMZ complex produced 740,000 b/d of crude in 2008, up from 550,700 b/d in 2007. Production has doubled in the last 3 years with a nitrogen reinjection program similar to one at Cantarell. Pemex expects KMZ production to peak at 820,000 b/d before declining to 810,000 b/d next year.

Pemex is investing heavily in KMZ to offset Cantarell’s decline. The field contains 18% of Mexico’s non-Cantarell proved reserves. However, KMZ crude is heavier than Maya crude. Analysts report Pemex documents show KMZ’s oil quality and production are falling due to encroachment of water and salt.

Some 20% of Pemex production is from onshore fields. The largest in the south, Puerto Ceiba, produced 50,000 b/d in 2008. The largest in the north is Arenque (10,000 b/d in 2008).

Potential contributor

The Chicontepec basin with 29 distinct fields spread over 2,400 sq miles northeast of Mexico City is potentially a large contributor to Pemex’s future production. It contains 54% of Mexico’s non-Cantarell proved reserves. Pemex plans to invest $11 billion over the next 4 years at Chicontepec. It currently produces 30,000 b/d, but Pemex hopes to increase production to 700,000 b/d by 2017. Pemex estimates Chicontepec contains possible reserves of 17.7 billion boe.

Most Chicontepec crude is heavy, some as heavy as 18° gravity. The reservoir is highly fractured and at low pressure, and the region lacks infrastructure for large-scale development. Low permeability makes extraction difficult. On top of that, some analysts suggest Pemex systematically exaggerates the recoverable oil in the basin.

Many industry observers believe Mexico’s oil production has peaked and will continue to decline. In March, EIA forecast Mexico will produce 2.9 million b/d of oil in 2009 and 2.7 million b/d in 2010. Last year Mexico enacted legislation to reform its oil industry so Pemex could better curb the production decline. The reform permits Pemex to create incentive-based service contracts with private companies. Pemex received greater autonomy under the reforms, including the ability to issue its own debt and establish more flexible mechanisms for procurement and investment.

Mexico opened its downstream gas industry to private operators in 1995 but prohibits any company from participating in more than one function (transportation, storage, or distribution). Gas consumption has increased for domestic power generation to free up oil for export. But Mexico is a net importer of gas, and increased consumption means increased imports from the US or via LNG.

PDVSA’s slide

PDVSA was created in 1975 when Venezuela first nationalized its oil industry. It’s the largest employer in Venezuela and accounts for a third of the country’s gross domestic product, 50% of the government’s revenue, and 80% of Venezuela’s exports earnings. It is among the five largest suppliers of crude to the US.

Venezuela has 99 billion bbl of proved oil reserves, the largest in South America (OGJ, Dec. 22, 2008, p. 20). Its gas reserves are 171 tcf.

In the 1990s, Venezuela increased opportunities for foreign and domestic oil companies under operating service contracts with PDVSA, granting operating rights to private-sector companies in selected fields with a cash fee paid per barrel of oil produced and delivered to PDVSA.

After President Hugo Chavez took office, however, he began raising taxes and royalties. Under threat of total nationalization, he forced companies to convert their operating service contracts into joint ventures with PDVSA as senior partner.

In 2002, nearly half of PDVSA’s employees walked off the job in protest against Chavez’s administration. But they lost the months-long strike, and Chavez fired 18,000 PDVSA workers. That, said critics, drained the company of technical knowledge and expertise. Industry analysts speculate the strike caused permanent damage to PDVSA’s production capacity.

Labor troubles are again bubbling in PDVSA. Dissident union leaders say many of the 100,000 workers employed by PDVSA and some contractors are disgruntled about overdue pay, a 6-month delay in renegotiating a contract with oil workers, and government efforts to consolidate all unions into a progovernment, socialist organization. Meanwhile, PDVSA is incorporating thousands of workers from recently nationalized oil service contractors.

In May Venezuelan troops seized the assets of 60 foreign and domestic oil service companies in a conflict over $14 billion owed by PDVSA. The company brought in more than $120 billion in revenue in 2008, but this year it will likely make just $50 billion.

Outside analysts estimate PDVSA needs to spend $3 billion/year just to maintain present production from existing fields, many with decline rates of 25%/year or more. Meanwhile, the government pulls billions from the company for nonoil investments.

Forced transition

In 2007, Chavez forced a transition of the four heavy oil projects to new structures giving PDVSA majority ownership. Of the six companies involved in the projects, ConocoPhillips and ExxonMobil Corp. walked away from massive investments.

Lynch said, “PDVSA is not so much in a downward spiral as a death spiral. They don’t have enough trained people to maintain operations, the government has diverted too much of their funds elsewhere, but more important, the prospect of attracting outside assistance is becoming all but impossible as the government uses PDVSA’s ‘accounts payable’ as a piggybank. Only massive change in the company and almost certainly in the government can fix things.”

Derman said, “As PDVSA becomes increasingly more isolated and cash-constrained, its production and revenue are likely to continue falling.” He said, “The short-term gains Venezuela achieved by effectively expropriating assets will precipitate long-term problems that will result in reduced production and reduced revenue. It is questionable whether the current strategy is sustainable.”

Yet Derman reported, “Some companies are considering a contrarian strategy [of] entering Venezuela now, believing that Venezuela’s strategy is not sustainable and that the rules will have to change again.”

Crude from Venezuela’s four major sedimentary basins has an average API gravity less than 20°. Much is also sour. PDVSA’s true level of production is difficult to determine. Officials claim Venezuela’s production capacity tops 3.4 million b/d. However, the Organization of Petroleum Exporting Countries reported Venezuelan oil production was up 23,000 b/d to 2.24 million b/d in May.

In 2007, according to EIA, Venezuela exported 1.9 million b/d of oil. The US received most of that, importing 1.36 million b/d of crude and petroleum products, down from 1.42 million b/d in 2006. Venezuelan oil exports to the US have been declining since peaking at 1.77 million b/d in 1997. PDVSA’s exports to China are on the rise, since the company has made a priority of diversifying sales away from the US. But sophisticated US refineries likely will still be processing Venezuela’s heavy, sour crude for the foreseeable future.

The Petrobras contrast

Viewed against the problems of Pemex and PDVSA, Petrobras appears to be doing everything right. It has gone partially public with some trading of its stock. It’s getting loans from China. It has developed an expertise and reputation for deepwater exploration and development that rivals the best of the IOCs, and it has taken that expertise into the Gulf of Mexico and foreign waters through its international operations. It has proven a profitable business partner for US service companies and IOCs. Recent discoveries have opened the promising presalt play in Brazilian waters. And it even has a major position in the production and market of ethanol.

Having worked with the company, Derman said, “Petrobras is unequivocally a first-rate organization with some of the most talented professionals anywhere.” Its presalt play “is the most exciting discovery in many decades.”

Derman said Petrobras’s international expansion provides an added advantage for the NOC beyond the obvious benefits. “After working extensively in the international arena, Petrobras understands the host government perspective and the international oil company perspective,” he said. “The professional thinking is at the cutting edge as the company is working in multiple places with a host of oil and gas companies. The challenge for Petrobras is to retain its professional staff, which is one of the best in the business.”

Another thing that sets Petrobras apart from many NOCs is that it is developing oil supplies for the Brazilian market rather than for export. Brazil is the 10th largest energy consumer in the world and is eclipsed in the Western Hemisphere only by the US and Canada. The Brazilian government has worked toward energy security since the energy crisis of the 1970s drove it to explore for oil and develop ethanol. Today Brazil is self-sufficient in liquid fuels.

State-controlled Petrobras is the dominant player in Brazil with strong positions upstream, midstream, and downstream. A constitutional amendment ended Petrobras’s monopoly in 1995. By 1997, regulators were in place to govern equally foreign and Brazilian oil companies. Exploration and production blocks are awarded competitively under a tax and royalty fiscal regime with the average royalty rate of 10%.

Still, EIA reported, “Foreign-operated oil projects are rare in Brazil.” Petrobras also has competition from private domestic companies. Yet it still controls over 95% of crude production in Brazil.

Petrobras’s resources

OPEC recently reported, “Among all non-OPEC countries, Brazil is seen to be on the top of the list in terms of supply growth. Various fields will start up and ramp up in Brazil, such as Parque Da Conchas (BC-10), Cachalote, Frade, Marlim Leste Jubati, Marlim Leste P-53, Marlim Sul P-51, and Pinauna. Additionally, biofuel production is anticipated to grow by around 60,000 b/d in 2010. Average oil supply from Brazil is estimated to stand at 2.79 million b/d in 2010.”

Petrobras’s total production dipped to 2.505 million boe/d in June from 2.547 million boe/d in May. Domestic oil production fell to 1.927 million b/d in June from 1.989 million b/d in May due to scheduled outages in Marlim Sul and Marlim fields and end of production from the Capixaba FPSO. International crude production by Petrobras climbed to 146,300 b/d from 136,300 b/d in May. Domestic gas output was 51.8 million cu m/day in June, up from 51 million cu m/day in May. Foreign gas production increased to 17.9 million cu m/day in June from 17 million cu m/day in May.

At the end of 2008, Petrobras’s domestic proved reserves of oil, condensate, and natural gas totaled 14.093 billion boe, up 1.2% from 2007. Proved reserves of oil and condensate equaled 11.969 billion bbl. Brazil’s proved reserves are the second-largest in South America after Venezuela’s. Most are in the Campos and Santos basins off the southeast coast. Proved gas reserves were 337.6 billion cu m. These figures do not include presalt discoveries in the Santos basin that are being evaluated.

Petrobras’s international proved reserves of oil, condensate, and natural gas totaled 992 million boe, down 9% from 2007. Proved reserves of oil and condensate were 496 million bbl. Proved natural gas reserves abroad amounted to 83.9 billion cu m. Improved recovery from oil fields in Argentina and Peru and the addition of Cascade field reserves in the US were offset by production, a decrease of assets in Ecuador, and revaluation of Nigerian reserves.

Presalt exploration

In 2007 Petrobras announced the discovery of Tupi field in the Santos basin in a subsalt zone in 18,000 ft of water. Tupi is the biggest oil discovery since Kashagan field off Kazakhstan and the largest in the Americas since 1976. Moreover, oil in the subsalt zones appears to be lighter and sweeter than most of Brazil’s existing production.

Additional subsalt discoveries include Carioca, Iara, and Guara. Preliminary industry estimates indicate recoverable subsalt oil and gas reserves could approach 56 billion boe.

In late June, the 4-BRSA-711-RJS (4-RJS-647) well confirmed reserves estimates of 5-8 billion boe of 30° gravity oil and natural gas in the Tupi area. An extended production test of the first two wells, Tupi-1 and Tupi Sul, began in May from the BW Cidade de Sao Vicente floating production, storage, and offloading vessel in 2,170 m of water in Block BM-S-11, 280 km off Rio de Janeiro. The FPSO is capable of producing 30,000 b/d. Petrobras is operator with 65% interest in the block. Partners are BG Group, 25%, and Galp Energia, 10%.

Petrobras expects to invest $28.9 billion in the presalt play by 2013. Brazilian officials say the play will secure the country’s energy self-sufficiency for half a century.

However, the great depths and pressures of subsalt deposits are technology challenges. The reserves also contain a high concentration of natural gas that will require additional facilities. As a result, said EIA, “Production from small pilot projects is possible in the next several years, but large-scale development of the subsalt reserves will likely not occur until well into the next decade.”

Brazil is one of the largest producers of ethanol and the largest exporter of the fuel. EIA earlier forecast Brazil’s ethanol production would reach 530,000 b/d in 2009. Most of the cars in Brazil are flex-fuel vehicles that can run on pure ethanol or an ethanol-gasoline mixture. Petrobras also has a dominant stake in the retail products market.

Natural gas production has developed slowly due to lack of pipeline capacity. EIA reported gas imports and high oil prices have increased substitution of gas for fuel oil for industry and power generation.