Strategic plan reiterates priorities in deep water oil


Petrobras’ oil target for the next five years, according to the 2023-2027 strategic plan, is aligned to the previous plan — which did not take the market by surprise. It ratifies the state-owned company’s priority to invest in the deep-water oil. However, a lower oil production forecast for the period drew attention, not because of volume, but for the company’s attention to the natural decline of those fields, which will require new contributions to maintain the desired production level.

Petrobras projects for 2023 a production of 2.6 million barrels of oil equivalent per day (boe/day), a measurement unit that includes the extraction of oil and natural gas, which translates into an operated production (in partnership with other companies) of 3.8 million boe/day, according to Fernando Borges, the head exploration and production, when presenting the 2023-2027 strategic plan last week.

The extracted volume would reach 3.1 million boe/day in 2027, the same estimated for 2026, with production operated at around 4.7 million boe/day. “Production is increasing,” the executive also said, “due to the development of assets in terms of pre-salt development mainly in this leverage period.”

In 2023, 74% of production will come from the pre-salt, rising to 78% in 2027. The figures are very close to those indicated in the 2022-2026 plan. However, Petrobras has indicated a reduction in production by 100,000 barrels per day, due to two reasons. The first cause is the co-participation agreement in the fields of Sépia and Atapu, both in the Santos Basin pre-salt.

According to Petrobras, this adjustment was necessary because the strategic plan 2022-2026 was released on November 24, 2021. A month later, on December 17, 2021, Petrobras acquired, in consortium with partner companies, the rights to exploration and production of the volumes exceeding the transfer of rights in the two fields, in the Second Round of Bids for the Surplus of the transfer of rights under the production-sharing regime for pre-salt oil fields.

Since the fields were under two regimes (transfer of rights and sharing), adjustments were needed in the participation of the companies in the fields. The 2023-2027 plan, in practice, reflects those adjustments, which resulted in a lower production projection. Another reason are adjustments in the interconnection schedule between wells, in the years 2024 and 2025, which were offset by the company’s total and commercial production projections.

For Ilan Arbetman, the chief economist of Ativa Investimentos, the loss of production in these years is compensated in the future with more value generation for Petrobras. “It’s something that brings efficiency gains in the future,” said Mr. Arbetman.

Mr. Borges highlighted the 9% increase in investments in exploration in new areas, to $5.5 billion, focused on replacing the production that will be lost with the natural decline of the fields in production. According to him, “we are fighting against a natural decline of about 10% a year. This means adding 300,000 boe/day to production in order to cope with the decline and maintain production at around 3 million barrels. One of the focal points is the Tupi field, one of the biggest producers in the pre-salt. According to Mr. Borges, Tupi is a field that will need to increase water injection, a technique used to extract more oil from reservoirs.

Petrobras raised its investment forecast for the next five years by a little more than $7 billion, to $64 billion, due to the incorporation of the Sepia and Atapu fields to Petrobras’ portfolio, among other reasons. Two-thirds of this amount is still destined for the pre-salt. Post-salt areas in the Campos and Sergipe-Alagoas basins will demand 24% of this amount, two percentage points less than the previous plan, but, according to Mr. Borges, the planned investment of $18 billion in the Campos Basin aims to offset the decline of other fields.

For financial services provider UBS, Petrobras was conservative in the production target, when considering, also, delays in the operation of fields in the Sergipe-Alagoas basin. UBS highlighted, however, the resilience of the projects in a stress scenario, with a barrel price at $35, and the 18 new platforms (FPSO, the acronym in English) starting operations, half of the new units in the world.

*By Fábio Couto — Rio de Janeiro

Source: Valor International

While the pre-salt oil exploration area whets the appetite of the world’s largest oil companies and consolidates itself as the main exploration frontier of Brazil, in general the other production poles in the country endure the decline of activity and low attractiveness of investment. Data from the National Petroleum Agency (ANP) show that if it were not for the Santos Basin, where the largest pre-salt discoveries are located, domestic production would end 2017 with its third consecutive year of decline.

The 14th Bidding Round held in September reinforced how large multinationals are focused on the pre-salt: the eight blocks purchased in ultra-deep waters of the Campos Basin, which border the pre-salt polygon and have potential for such discoveries, accounted for 75% of the investment commitments assumed by oil companies in the bidding process, and for 95% of the auction’s signing bonuses.

These were the areas that guaranteed the round’s successful R$3.8 billion revenue, and where the most contested bids of the auction took place, with the presence of companies such as Petrobras and Exxon Mobil, Shell, BP, Total, Repsol and CNOOC.

But outside of the Campos Basis, large multinationals were interested in a few assets in the Espírito Santo Basin (CNOOC and Repsol) and in Sergipe-Alagoas (Exxon) — one of the main bets in deep waters outside of the traditional Campos and Santos axis. Actually, the number of blocks auctioned in the 14th Round (35) was the lowest since the ANP’s 4th Round in 2002, when 21 areas were sold.

Edmar Almeida, professor of the Energy Economics Group of the Federal University of Rio de Janeiro (GEE/UFRJ), points out that the attractiveness of the 14th Round is linked to a specific geological situation, the pre-salt, and that the low interest in the remaining basins is an important yellow light for the oil industry.

According to ANP data, national production of oil and gas has shown an average of 3.3 million barrels of oil equivalent (BOE/day) for the year to date, a 17% increase (or 498,000 BOE/day) compared to 2014. This growth, however, has been basically sustained by the Santos Basin, whose production rose 190% in the period (917,000 BOE/day). Production of traditional basins such as Campos, Sergipe-Alagoas, Potiguar and Recôncavo has been falling year after year and has already shown a reduction of 370,000 BOE/day in the period.

Some of the Brazilian basins have been affected, in particular, by demand. This is the case, for example, of Camamu and Parnaíba, which produce essentially natural gas and whose production depend on the consumer market — in the case of Parnaíba, from the operation of the Eneva thermoelectric plants in Maranhão. But in general, the smaller production seen in other basins outside the pre-salt reflects the natural decline of the fields — which is accentuated when there are no investments in revitalization projects.

The market expects the recovery of investments in mature areas under Petrobras’s assets sales program. The state-owned oil company, which has concentrated its investment in the pre-salt sector recently, may make room for other companies, some smaller and specialized in mature fields, which could invest in the recovery of production of such assets.

Adriano Pires, director of the Brazilian Center for Infrastructure (CBIE), believes that as new oil companies take over the operation of these mature fields, investment will increase quickly.

“Investment in mature fields has faster impacts than exploratory block auctions. As Petrobras has practically abandoned mature fields, I believe that recovery of production in these areas will happen quickly,” he says.

Today, Petrobras has 100 onshore and offshore concessions in divestiture stage. These assets, located in mature areas, account for oil and gas production of 111,000 BOE/day, or 4.2% of the total volume produced by the Brazilian oil company. The company also signed an agreement with Norway’s Statoil late last month to study joint partnerships in the recovery of mature fields in the Campos Basin’s post-salt.

However, a study developed by the GEE/UFRJ, in partnership with the Brazilian Petroleum Institute (IBP), shows that projects outside of the pre-salt area present challenging economics and that, therefore, it is fundamental that the government confronts the barriers that may hinder investments in more mature basins.

This year, for example, ANP approved a 10% to 5% reduction of royalties on the incremental production provided by the revitalization of mature fields. With incentives for investment, the agency sees potential so the recovery factor (amount of recoverable oil within a reserve) of mature areas from the Campos Basin can be increased to 30% from 24%. The ANP estimates that each percentage-point increase in the factor can generate $18 billion in investment and 2.2 billion barrels of reserves.

The UFRJ study also suggests, among other measures, the reduction of risks in environmental licensing; the sharing of transportation and storage infrastructure; and an oil procurement policy for domestic refineries.

Mr. Almeida, with the GEE, emphasizes the importance of dispersing production beyond the pre-salt. For him, the production decline of more mature basins may not affect Brazilian self-sufficiency in oil and gas supply in the short and medium terms, but it prevents the maximization of the economic impacts of the sector’s investments throughout the national territory; and security of supply, guaranteed by the diversification of sources.

Mr. Almeida also stresses the importance of encouraging gas production in shallow waters and offshore, in order to ensure a competitive supply to the market.

“It is worth mentioning that production of natural gas in deep waters presents great challenges due to its costs of disposal and, particularly in the pre-salt, [there are] relevant production costs due to the depth of reservoirs and level of contamination, thus affecting its commerciality”, said Mr. Almeida in an article published in the blog “Infopetro.”

Source: Valor Econômico

Exxon Mobil Corp’s big bet on Brazil’s offshore Campos basin shows its willingness to pay up to replenish its reserves and may pave the way for hefty bids in October auctions in the country’s rich pre-salt areas, analysts said.

Marking a return to Brazilian exploration after a five-year absence, Exxon took eight blocks in the coveted basin, one of Brazil’s most productive, at an auction on Wednesday. Six were taken in partnership with state-run Petroleo Brasileiro (Petrobras).

The auction’s record take included an Exxon bid of 2.24 billion reais ($704 million) for one block, Brazil’s highest-ever such bid.

That showed how oil companies that can afford significant overheads are willing to shell out for and develop high quality reserves in far-flung locations, despite oil prices that have roughly halved since 2014.

“If anyone can bring a low-cost approach to doing something as big and complex as that, it is probably Exxon Mobil,” said Brian Youngberg, an analyst at Edward Jones.

 Youngberg said he also expects Exxon to be involved in October auctions of blocks in the adjoining pre-salt area, where hydrocarbons are trapped under layers of salt beneath the ocean floor.

Exxon did not immediately respond to a question about its potential participation in the October auctions.

Exxon, with a market value of around $350 billion, has spent heavily this year on oil and natural gas expansion projects to replenish its diminishing reserves, seeking to counteract concerns that it is falling behind peers in exploration and production.

Investments have included the Permian Basin in the United States, offshore Guyana, and Argentina’s Vaca Muerta shale play.

The Brazil deal is a “further sign of the company’s urgency to replenish its resources base,” analysts at Tudor, Pickering Holt & Co said on Thursday, adding that the Campos Basin deal was a bullish sign for Brazil’s pre-salt block auctions.

Wednesday’s record bid was around 5 times as much as the nearest one from Royal Dutch Shell and Repsol. Petrobras said it had information that some of the Campos blocks had high-potential pre-salt reserves.

Before the auction, Exxon was among the few oil majors without an exploration presence in Brazil’s recently discovered large offshore fields.

“For Exxon Mobil, a lack of presence in Brazil’s pre-salt has been arguably the biggest gap in its portfolio, especially now that Shell holds a dominant position in this prolific, relatively low-breakeven play,” Horacio Cuenca, a researcher at Wood Mackenzie, said in a client statement.

Exxon abandoned drilling efforts in the nearby Santos basin in 2012 following disappointing results.

But a series of policy changes under market-friendly President Michel Temer, including a reduction of requirements that forced foreign businesses to use local partners, will likely tempt investors to return to Latin America’s no.1 economy, analysts said.

Source: Reuters