A Brand New Brazil

It’s Carnival time in Brazil, and the country has good reason to party. Brazil’s time on the world stage has arrived, and the samba-loving, football-crazy nation is more than ready. The country is hosting the 2014 World Cup; it has won the coveted 2016 Olympics; and its stock market closed out 2009 with 20 months of consecutive gains.

Moreover, Brazil has recently discovered immense, high-quality offshore oil reserves in deep pre-salt sediments. In November 2007, Tupi Field was unveiled by Petrobras, the Brazilian government-controlled entity, and its partners BG Group and Galp Energia. The 5- to 8-billion-barrel find—some 175 miles off the coast of Rio de Janeiro in the Santos Basin—has kindled keen interest around the globe. Brazil already ranked as a considerable deepwater producer, but Tupi has stepped up its prospects sky-high.

Brazil held 12.6 billion barrels of oil reserves at the end of 2008, according to BP’s annual 2009 energy review. The Agencia Nacional de Petroleo (ANP), Brazil’s petroleum regulatory agency, today estimates Brazil’s pre-salt potential at 80 billion barrels, an astonishing figure. It’s been decades since any country has experienced such a dramatic and weighty turnaround in its oil estate.

Overleaf, enormous oil finds 175 miles of the coast of Rio de Janeiro in the pre-salt province have infused the fascinating city with fresh optimism.

Tupi rates as the greatest find in the world since 2000, when 13-billion-barrel Kashagan was discovered in the Kazakh sector of the Caspian Sea. It marks the largest find in the Western Hemisphere since 1976, when Mexico opened 17-billion-barrel Cantarell Field.

Adding to its allure: Tupi, drilled on Block BM-S-11 in 7,000 feet of water to a depth of some 17,000 feet, contains crude that’s nearly 30-degrees API gravity, amazingly light by Brazilian standards. Most of the nation’s fields produce much heavier oil, with average gravity in the high teens.

And, Tupi was not a stand-alone discovery. Announcement of the Carioca find followed in the fall of 2007, and during 2008, Jupiter, Guará and Iara were drilled. Those three ranked as the top finds worldwide that year. Iara alone holds 3- to 4 billion barrels of recoverable oil, according to Petrobras.

The accumulations lie below a thick, pervasive salt layer. The salt—6,500 feet thick at Tupi—shielded the sediments below from explorers until the recent combination of improved seismic imaging and deepwater drilling capabilities opened the new frontier. And, thanks to the properties of salt, pressures and temperatures in the deep reservoirs were lower than normally expected at those depths. That’s why liquids are present in the pre-salt, and why the oil quality is high.

The reservoir rocks’ striking characteristics are another reason the finds are so grand. Tupi boasts more than 650 feet of extremely porous and permeable carbonates (composed of stromatolites and coquinas), and these rock types are laterally extensive. Indications are they may stretch for 1,200 miles along a broad oceanic ridge.

The pre-salt province is vast. It sprawls across 57,500 square miles, stretching from the Santos through the Campos and north into the Espírito Santo basins. This is continental-scale geology, related to the breakup of an early continental mass, seafloor rifting and the formation of present-day South America and Africa.

Pre-salt discoveries to date have clustered in the Santos and Campos basins. The latter is a mighty post-salt producer as well, and has been the traditional playground for Petrobras.

In 2009, Petrobras produced 2 million barrels a day from its home country, led by such Campos fields as 3.5-billion-barrel Roncador and 2-billion-barrel Marlim.

Jose Sergio Gabrielli de Azevedo, president and chief executve officer of Petrobras, is mobbed by jornalists at a press conference at the American Association of Petroleum Geologists International Conference and Exihibition in Rio de Janeiro.

Growth in deepwater production from post-salt turbidite fields was already pushing Brazil’s oil volumes up sharply. In just a dozen years, the country has jumped from an importer of crude to a self-sufficient producer. With the sterling potential of the pre-salt, and major pre-salt developments already in progress, Brazil’s next step will be to join the society of top exporter nations.

Spearheading growth

Brazil intends to make this move through Petrobras, its state firm. Among the national oil companies (NOCs) that populate Latin America, Petrobras resides in a league of its own. It is an effective, dynamic company in the vanguard of deepwater technology. Semi-public Petrobras is listed on the São Paulo stock exchange, and the Brazilian government owns 55% of voting shares.

“We are planning to add production of more than 2 million barrels equivalent per day by 2020,” said Jose Sergio Gabrielli de Azevedo, president and chief executive officer of Petrobras, speaking at the American Association of Petroleum Geologists’ International Conference and Exhibition in Rio de Janeiro in November 2009. “We will go from 2.7 million barrels of oil equivalent (BOE) per day today to 5.7 million BOE a day by 2020. It’s a very large growth rate, of 75%, and it’s an amazing challenge that we have.”

Marco Antonio Martins Almeida secretary of oil, natural gas and renewable fuels, says the huge size of the huge size of the pre-salt finds and the apparent low exploration risk cause Brazil to reevaluate its concession model.

To accomplish this gargantuan feat, the company will spend $34 billion annually between now and 2013; its capex forecast calls for $111.4 billion to be lavished on the pre-salt trend alone between 2009 and 2020.

“We rely on our own drilling. Our growth depends on our discoveries and our success in exploration,” he says.

That success has been exceptional. “In Tupi, Guará, Iara and Whale’s Park we have already discovered a volume estimated between 10.6 and 16 billion barrels of recoverable oil. We will transform those barrels into proven reserves as fast as we can.”

Petrobras has drilled 47 wells in the new pre-salt trend, and found oil in 41. Of the 13 wells drilled in the Santos Basin, all are successful. “We think this is a very prolific, new exploratory frontier,” says Gabrielli.

The company’s challenges are many, nonetheless. It needs to learn much more about reservoir quality and variability. The new deposits are far offshore, presenting logistical difficulties. Subsea designs, production-system integrity and flow assurance are all critical elements.

Still, Petrobras confidently states the massive developments lie within its expertise. “We don’t think we have any big technologic problems for the floating system, the subsea system, the wellhead systems, or for drilling difficulties or production,” says Gabrielli.

What is still unclear is how the reservoirs will behave. To gain that knowledge, Petrobras is conducting extended well tests at Tupi and Whale’s Park. “Those two tests are going to give a lot of information on pressure gradients, flows, porosities and permeabilities,” he says. In Tupi, Petrobras now produces 15,000 to 20,000 barrels a day, and in Whale’s Park, between 10,000 and 15,000 barrels daily.

By 2013, the company expects pre-salt fields to make 219,000 barrels a day; its net share will be 152,000 barrels. These volumes will expand rapidly. By 2020, the pre-salt trend should be delivering 1.8 million barrels a day, and 1.18 million barrels of that will be net to Petrobras. Moreover, this crude will flow from finds already made: “We are not talking about basing our future growth on new discoveries that are going to come,” notes Gabrielli.

The addition of pre-salt oil, if it develops to its full potential, would catapult Brazil into the exclusive club of the world's top producing nations.

In addition to pre-salt, Petrobras invests domestically in post-salt offshore developments, onshore concessions, natural gas exploration and development and five new refineries. Of its target production of 5.7 million BOE per day in 2020, 5 million will come from Brazil.

Subsalt to pre-salt

Houston-based Anadarko Petroleum Corp. was the first operator to join Petrobras at the pre-salt party. The U.S. company drilled its Wahoo discovery in 2008 in the Campos Basin on Block BM-C-30. It encountered 195 feet of high-quality, carbonate reservoir, similar to that reported in Petrobras’ pre-salt discoveries.

Anadarko and its predecessors had been active offshore Brazil for a number of years. Some of the company’s blocks in the Campos and Espírito Santo basins were awarded in 2004 in ANP’s 6th round. In total, it holds interests in seven exploration blocks that cover approximately 1 million gross acres.

“When we came into these basins, everyone had a gleam in their eye about pre-salt, but the big reservoir risk had not been resolved,” says Frank Patterson, vice president of international exploration. “We knew there was a pre-salt opportunity in the Wahoo block in particular, but it was extremely high-risk.”

Commercial targets were post-salt. The company drilled two post-salt prospects for the initial commitment wells on blocks BM-C-30 and BM-C-32. (Anadarko operates the former and its partner, Devon Energy Corp., operates the latter.) What it found were excellent reservoir rocks on well-defined structures, but no hydrocarbon charge.

“The oil was all trapped below the salt,” says Patterson.

After Tupi was discovered, Anadarko went after the pre-salt on its concessions.

The company already had extensive experience in the subsalt Gulf of Mexico play, but the two plays have distinct geological differences. In Brazil’s pre-salt trend, the deeper sediments were formed before the salt was deposited. In the Gulf of Mexico’s subsalt, the salt moved above younger sediments. Reservoirs in the Gulf are primarily sandstones, while those in Brazil are carbonates.

“The salt in Brazil is also much better behaved. It doesn’t have as much deformation, so the seismic imaging is a little better than in the Gulf of Mexico,” says Patterson.

Relevant technologies that do cross into both plays include seismic processing and imaging techniques and drilling and operational practices. The Brazilian wells are some 10,000 feet shallower than the 30,000-foot-plus depths now common in the Gulf of Mexico, but the Brazilian rocks are much harder. Penetration rate and bit selection are paramount.

“It’s flat-out slow drilling at times,” says Greg Hebertson, Anadarko’s exploration manager for Brazil. Each Campos Basin well can require 90 to 140 days to drill, and daily operational rates typically run $800,000 to $1 million a day.

Another key difference: pre-salt fields in Brazil can contain billions of barrels. A good-sized Gulf of Mexico reservoir might cover thousands of acres; in Brazil, a good-sized reservoir spans tens of thousands of acres. “Pay thicknesses in Brazil are less than in the Gulf of Mexico, but the areal extent in Brazil can be much greater,” says Patterson.

Wahoo, like other finds in Brazil’s pre-salt, has phenomenal scale. In November 2009, Anadarko’s Wahoo #2 appraisal/exploration well confirmed that the main pay section extended at least five miles north of the discovery.

Anadarko now has interests in another discovery, in adjacent Block BM-C-32, 16 miles north of Wahoo. The Itaipu prospect, operated by Devon Energy, intersected more than 90 net feet of oil pay in a high-quality, pre-salt reservoir. It was drilled in 4,400 feet of water to a total depth of approximately 16,300 feet.

“Each of our blocks is equivalent in size to 30 Gulf of Mexico blocks,” says Hebertson. “It’s a huge area, and we have already proved up hydrocarbon accumulations across some 16 miles.”

For Anadarko, as for the other pre-salt participants, the key question going forward is how many wells it will take to efficiently drain the resources. “We think our reservoirs are similar to those described elsewhere in the pre-salt trend,” says Hebertson.

“We have Cretaceous-age, microbial carbonates, and we have seen some indications that our rocks are at the high end of the quality range.”

Still, the reservoirs are very complex and analogs are scarce. The closest parallels are some of the tremendous, onshore carbonate fields in the Middle East. “We have a lot of information we need to gather,” Hebertson says. “We are collecting cores and working on reservoir characterization.”

Anadarko’s finds lie just seaward of Petrobras’ Jubarte/Whale’s Park complex, where pre-salt reservoirs are estimated to contain some 2 billion barrels in resources. One of Petrobras’ two long-term production tests in the pre-salt is at Whale’s Park.

Currently, Anadarko is drilling a sidetrack in the Wahoo appraisal. After it finishes, it will move its contracted drillship, the Deepwater Millennium, to the Wahoo discovery for a drillstem test. Up to two exploration/appraisal wells are planned on the Wahoo block this year. It will keep the drillship working throughout 2010. Anadarko also has an identified a pre-salt prospect on BM-C-29 in about 260 feet of water that it plans to drill with a jackup later this year.

Additionally, the company is continuing its program on its Espírito Santo concessions, which are operated by Petrobras. The partners plan to continue exploring both post- and pre-salt reservoirs. “We’ve had some geologic successes in the Espírito Santo Basin, which is more of an emerging area. We do have some additional opportunity there, and we’re looking at a drilling window perhaps late this year,” Hebertson says.

“Brazil’s pre-salt is one of two plays in the world right now surrendering billion-barrel opportunities,” says Patterson. “We feel very fortunate to be in this play. We’re going to stay very busy in Brazil.”

Shallow-water success

There’s much more to Brazil’s E&P scene than just pre-salt, however. The huge focus on pre-salt has perhaps diverted world attention from other strongly economic E&P ventures, but some firms have been actively pursuing these less flashy prospects.

The meteoric success of OGX Petroleo & Gas Participacoes SA has surprised and enlivened the Brazilian industry. The company, controlled by Eike Batista, Brazil’s richest man, burst on the Brazilian E&P scene in November 2007 when it purchased interests in 21 blocks containing 1.58 million acres in the truncated 9th licensing round. (See sidebar.)

With pre-salt blocks taken abruptly off the table, OGX concentrated on shallow-water blocks in the Espírito Santo, Campos, Para-Maranhao and Santos basins. The company, formed in June 2007, went to the sale armed with $1.3 billion it had raised through private placement.

After its big wins at the 9th round, the fledgling firm farmed into BM-S-29, a Santos Basin block.

OGX went public in June 2008. It raised $3.5 billion in its initial sale, which at the time was Brazil’s largest-ever IPO.

Its next move was to expand to the onshore. It layered on a project comprised of a 70% interest in seven blocks in the Parnaiba Basin. In September 2009, OGX released a DeGolyer & MacNaughton report that calculated net, risked potential resources of 6.7 billion barrels of oil equivalent on its 29 exploratory blocks.

Now it has made three discoveries on three separate offshore concessions. In October 2009, it announced a find of between 500 million and 1.5 billion barrels of oil in BM-C-43, in the shallow-water Campos Basin. In December, it made a 2-billion-barrel discovery on adjacent Block BM-C-41. The 1-OGX-2A-RJS encountered hydrocarbons in five separate intervals at a location 50 miles off the coast.

Most recently, it reported that its 1-OGX-4-RJS on BM-C-42 intersected a 295-foot oil column in Eocene sandstones. Net pay is 55 feet. That well was drilling towards a projected total depth of 11,150 feet at press time.

OGX plans to drill 79 wells by 2013. This year, it will drill 17 wells in the Campos Basin and one each in the Santos and Paranaiba basins. During the past 12 months, its shares have tripled in value. It notes it has sufficient cash to fund all exploratory capex, initial production, and new farm-in and acquisition opportunities.

Private interests

Private firm Brasoil do Brasil is another company planning to grow right along with Brazil’s upstream. Don Parker, president and chief executive officer, heads up the Brazilian firm. “Our management is Canadian, but we are based in Rio de Janeiro,” he says.

Brasoil officially formed in February 2007, but its interest in Brazil dates back to 2005. That’s when Queiroz Galvao, a leading domestic independent, indicated it wanted to sell a portfolio of assets.

Queiroz Galvao had struck natural gas at Manati, a shallow, offshore exploration project in the Camamu Basin, in the state of Bahia. Petrobras operated the block with a 35% interest; Queiroz Galvao had 55%.

Manati is one of the largest nonassociated gas finds in Brazil. The future Brasoil management team looked at the project when just two wells had been drilled—the discovery and a delineation test. “When we first saw Manati there were only a couple of drillstem tests, but the wells had the best gas logs we’d ever seen,” says Parker.

Brasoil, funded by Goldman Sachs, a group of investors organized by Compass Advisers and Brascan Corp., bought the Queiroz Galvao package in 2007. The deal included a 10% working interest in Manati, interests in Coral and Cavalo Marinho fields in the Santos Basin, and BT-REC-8, a block in the onshore Reconcavo Basin.

That November the new firm also participated in the 9th round. It went after blocks in the shallow-water Santos Basin with a Norwegian firm, a partner in Manati.

The partnership won three contiguous blocks in that sale, S-M 1035, 1036 and 1100. The Norwegian partner operates and each company has 50%. They have committed to shoot 3-D seismic on the blocks, each of which covers 65 square miles.

The partners just completed acquisition of a 270-square-mile 3-D seismic survey across the three blocks.

“We’re on the shelf, right before the shelf break,” says Parker. “We’re playing turbidite sloughs.” The blocks, in 550 to 650 feet of water, are on the west side of the pre-salt area; at Brasoil’s concessions the salt is intermittent and forms diapirs and salt pillows.

“We looked at 40 possible blocks and high-graded to the three that we thought had the best salt windows as well as upper structures. Those are the ones we bid on and won.”

Brasoil has already identified three structures of high interest between 13,000 and 18,000 feet deep in the post-salt section. “We hope to see if we have pre-salt potential on the 3-D seismic as well.”

The neighborhood is a good one. On one side of its acreage, Petrobras recently discovered light oil at 6,500 feet in the Oligocene at Tiro and Sidon fields. One test made 12,000 barrels a day, and the NOC has said recoverable oil volumes are 150 million barrels. On the other side lies Piracuca, a new turbidite field with 550 million BOE in place, also drilled by Petrobras.

“If you were in the Gulf of Mexico, our prospects would have been drilled several decades ago,” says Parker. “There are less than 300 wells drilled here in an area the size of the Gulf of Mexico.”

Brasoil and its partner have until March 2011 to make drilling elections on their blocks. Currently, the companies are interpreting their 3-D seismic, fine-tuning prospects and identifying specific locations. The wells will likely range from $75- to $100 million, based on the experiences of other operators.

Back at Manati, Petrobras has drilled six wells to date and plans to continue development. Manati, located in 120 feet of water about six miles from shore, features a continuous, 1,000-foot gas column. Half of the rock has more than 1 darcy of permeability.

The partners have been producing gas since January 2007. The field currently produces 250 million cubic feet per day and its estimated ultimate recovery is more than 1 trillion cubic feet (Tcf).

“Manati could produce more: the wells have high deliverability, and the pipeline has capacity for about 385 million per day,” says Parker.

For Brasoil, Manati has been a marvelous starting point. The field provides stable cash flow and has been a bridge to build relationships with Petrobras, its other partners and the community.

“As an entry point into the country, it’s been a great place to understand how things work,” says Parker.

Additionally, Manati was developed under a fixed-price contract, so its gas fetches premium prices compared to those prevalent in North America. “Currently we get $6.11 per thousand cubic feet. The gas is very dry and needs very little treating, and operating costs are just around $0.45 per thousand.” Royalties are also reasonable—7.5%—because the government is incentivizing the development. “Our netbacks are more than $5 per thousand,” he says.

Brasoil also picked up an onshore block in the Reconcavo Basin in the 9th round. It may farm out REC-T-226, however, says Parker, because it is focusing on the offshore.

“We’re preparing our team for another round of bidding, and we’re working on partnering and on grass-roots prospects,” he says. The company is most interested in light-gravity oil and natural gas. “We’d like to get a bigger position in the post-salt, shallow water, and enter a consortium to participate in the pre-salt.”

A new independent

The pre-salt play has been dazzling, but there are many less luminous plays that are quite attractive across Brazil. The country has hardly been scratched by the drillbit, says Marcio Rocha Mello, chief executive officer of HRT Oil & Gas. The E&P firm is a spanking-new spin-off from HRT Petroleum, South America’s biggest service company.

Once Brazil’s prolific offshore fields were discovered, onshore exploration went quiet. But opportunities in onshore Brazil loom large.

HRT plans to become Brazil’s leading onshore independent, and the place it has chosen to start this campaign is the Solimoes Basin, deep in Brazil’s interior.

The remote Paleozoic basin is shallow, with drill depths from 5,000 to 9,000 feet, and lightly explored. Only 250 wells have been drilled in an area the size of Europe.

And yet, the drilling that was done was quite successful. “Solimoes Basin has one-third of all the gas reserves in Brazil, and today it is the largest producer of light oil in Brazil,” says Mello.

“The reservoirs are Carboniferous sandstones, 2 to 3 darcies in permeability and 25% to ­­­30% porosity. The potential is enormous,” says Mello. Throw in big anticlines, with reverse faults, and it makes an unbelievable petroleum system. Furthermore, the Solimoes boasts pre-salt potential, albeit in the Paleozoic instead of the Mesozoic as in the offshore trend.

“The Solimoes was forgotten for a long time, because Brazil’s attention all moved to the offshore,” he says. “Brazil is an oil-prone country, and we import 60% of our gas from Bolivia. The Solimoes is the place for gas in Brazil, because it has the largest potential for gas of any province.”

And, although it is far from Brazil’s 4,600-mile Atlantic coastline, where most of the country’s 185 million people reside, oil and gas pipelines bring Solimoes production to Manaus. Petrobras just completed a $1.5-billion major pipeline project to improve the region’s infrastructure.

Mello plans to start drilling this summer. The new firm has 51% interests and operatorship in 19,500 square miles in 21 blocks in the Solimoes, farmed in from Petra Energia and M&S Brasil. “Our blocks cover an area twice the size of Belgium,” he says. “The blocks already have 1.1 Tcf of reserves, and we expect 10- to 20 Tcf of gas.” HRT’s plans call for 40 wells in the next four years.

The new firm is starting out with $275 million in private-placement funds. “That’s enough for the next two years,” says Mello. “Our aim is to be the largest gas producer in Brazil.”

And while it is initially concentrating in the Solimoes Basin, HRT is not restricting itself. All of Brazil is on its list, and it is even looking at international projects in such areas as Namibia, Colombia and Angola.

“We intend to certify about a billion barrels, open some wells and have production in 2010.”

Field rejuvenation

Beyond pre-salt exploration, shallow-water drilling and natural gas developments, Brazil offers yet another class of opportunities: rehabilitation of old oilfields.

Denver-based Central Resources Inc. started looking at Brazil about three years ago, says Paul Zecchi, president and chief executive officer. The company is active in Argentina and it saw Brazil start to open. “We think there’s a lot of opportunity in Brazil. Government regulations are favorable, and the country is on a trajectory of growth.”

Old, onshore oil fields are becoming available. “The government wants Petrobras to step aside from marginal onshore production and concentrate on the offshore,” says Zecchi. “It is encouraging Petrobras to release some of its older fields.”

Indeed, a number of mature fields fell so far down on Petrobras’ priority list that they didn’t attract the manpower or capital required to fully exploit their oil. That spells opportunity for a firm such as Central, with the resources to devote to these shaken-off assets.

Central is in the throes of a purchase-and-sale agreement on a package of onshore properties. The company specializes in marginal-well production: “We know old fields—such things as how to handle high-water cuts—and how to make money,” says Zecchi.

Central plans to drill development wells and install waterfloods on its newly acquired properties. It’s tame nuts-and-bolts work, compared to the glamour of bringing in enormous offshore producers, but it’s Central’s niche.

“For us, Petrobras and the government have been most receptive. They are quite interested in getting the old production rejuvenated and moving forward again.”

Positives abound: Brazil’s fiscal terms are good, cost of entry is low and skilled labor is available. Regulations are not onerous, and the legal system is sophisticated. Finally, foreign firms are able to bring money in and out of the country without too much difficulty.

Drawbacks are present, naturally, but they are not extreme. They include entrenched unions, higher operating costs than in the U.S. and the language barrier.

“For U.S. producers, you have to get over the mentality that there’s no place like home. That’s true, but Brazil is a place where you can make good money,” says Zecchi.

That’s certainly what Central intends to do. The new purchase will boost its size by 20% and provide it an entrée into a country that is rapidly becoming one of the world’s major energy hubs.

Without doubt, Brazil is on the rise. It offers major new production possibilities from its pre-salt province; its NOC is technically and financially sophisticated; it hosts a vigorous oil-service sector; and its government is striking the delicate balance between encouraging outside investment and protecting its national interests.

And, it’s home to Carnival, the world’s best party.

Pre-Salt Shuffle In 1997, Brazil passed an oil law opening its upstream to foreign investment. It crafted a workable and transparent system, and trimmed government influence in exploration and production endeavors. The nation’s fiscal regime fell solidly in the middle of its South American neighbors, between the extreme strictures of Venezuela and the openness of Peru. Brazil has employed a three-leg strategy of income taxes, royalties and special participation rates. The latter are royalties that slide based on age of production and water depth; more fruitful fields pay higher rates. After the Tupi discovery and several subsequent pre-salt finds were announced, the government realized that the pre-salt trend was vast and potentially highly prolific. It wanted to take some time to consider a new approach. The Agencia Nacional de Petroleo pulled 41 offshore blocks from Brazil’s 9th licensing round, taking choice acreage in the pre-salt trend off the market. “Since 1997 the concession models have been a great success,” said Marco Antonio Martins Almeida, secretary of oil, natural gas and renewable fuels, Brazilian Ministry of Mines and Energy, speaking at the American Association of Petroleum Geologists’ International Conference and Exhibition in Rio de Janeiro in November 2009. “They allowed us to find these new fields.” In the 57,500-square-mile pre-salt trend, 28% had already been offered in concession contracts. And while Petrobras operated many of the blocks, foreign partners held big slices. BG Group, Repsol, Shell and Galp Energia held stakes, and others held blocks that were not yet drilled. Some 97% of Petrobras’ current domestic production comes from concessions it owns alone, but it has partners in 38% of the areas under development, and partners in 53% of blocks under exploration or appraisal. Brazil was frankly afraid it was losing its grip on its national treasure. Already, Tupi (5- to 8 billion barrels), Iara (3- to 8 billion barrels), Guará (1.1- to 2 billion barrels) and Whale’s Park (1.5- to 2 billion barrels) have been found. And, exploration risk appears to be low. “Eighty-seven percent of exploration wells have been successful,” says Almeida. “That was the motivation for us to reevaluate the regulatory model for the areas without concessions.” Areas already under concession will not be changed, but Brazil has determined that production-sharing agreements (PSAs) will be in its best interests going forward. The new terms call for Petrobras to operate all future pre-salt PSAs, and hold a minimum 30% interest. To capitalize Petrobras, the government will grant Petrobras rights to 5 billion barrels of oil in offshore areas that are currently not under contract, and Petrobras will issue new shares to pay for the rights. The offer will be priced at about three times the value of the oil, and the government will get about 30% of the shares. Additionally, a state company, Petrosal, will be created to manage the government’s interest in the pre-salt fields. The new company will be a consortium partner and will act according to the best practices of the international industry, says Almeida. Finally, a new social fund has been set up, to be funded by such sources as royalties, signing bonuses and PSA revenues. “It will be used in Brazil on education, culture, environment, science and technology, and health,” he says. Challenges faced by the government include establishing the parameters of the new contracts so the blocks are still attractive; constructing Petrosal, the new public company; and ensuring that local content is really local. Two of the government’s decisions are political, notes Almeida: Petrobras will be the exclusive operator of the pre-salt PSAs, and oilfield equipment and technologies for use in the pre-salt should come from inside Brazil. At the close of 2009, Brazilian officials announced that the highly anticipated 11th round of bidding will likely occur this spring. But, the 11th round will not offer pre-salt licenses, as the new rules are still being debated in the Brazilian National Congress. “By March 2010 the new model should be completely approved,” says Almeida. At present, debates about royalty sharing among states and the capitalization of Petrobras are ongoing. Given that it’s an election year in Brazil, the March time frame may be somewhat optimistic.