February 2020

Regional Report: Brazil

Short-term gains; long-term questions
Mike Slaton / Contributing Editor

An ambitious array of Brazilian government initiatives aimed at reversing declines in overall production were expected to pay off in 2019. Brazilian officials said the turnaround was critical.

In fact, overall production was up—largely from pre-salt projects coming online. It reached record levels in November 2019, at 3.09 MMbopd, Fig. 1. In the year prior, in spite of pre-salt growth, November production declined 5.9%, to an annual average of 2.5 MMbopd, reported the Brazilian National Agency for Petroleum, Natural Gas and Biofuels (ANP).

However, lease sales, the path to increasing production outside the pre-salt, did not fulfill expectations. The 2019 rounds saw majors sit out much of the bidding, leaving many properties untouched and with few exceptions, providing little competition to state-controlled Petrobras. In contrast, bidding rounds in 2017 and 2018 resulted in the acquisition of 72 blocks by dozens of companies, $7.5 billion in signing bonuses, and enthusiastic competition, Fig. 2.

The 2019 outcome was unsettling because of what it suggests about improving overall production. While pre-salt production growth will likely be sustained by ongoing and planned installations of FPSOs, perhaps reaching 3.2 MMbopd by 2022, Wood Mackenzie analysts predict the rest of Brazilian production, together, is a net negative.

Most of Brazil’s production is from pre-salt assets. While pre-salt production between 2012 and 2018 rose a remarkable 729%, onshore production fell 38% and post-salt Campos basin oil production fell 41%. Average pre-salt production per well in 2018 was 17,655 bopd from 85 wells; the conventional offshore per well average was 1,650 bopd from 628 wells; and onshore production averaged 16 bopd from 6,683 wells.

Turning around this precipitous fall in conventional offshore and onshore production is a key focus of government initiatives. Results of the 2019 lease sales have added more uncertainty to the equation, and created questions about future rounds.


Brazil’s efforts to maximize recovery, increase reserves, and attract investors include more attractive contracts in bidding rounds; reductions in royalties for incremental production from mature fields; a new R&D strategy; reserve-based lending; local content changes; and divestment (see “Changing the game,” World Oil, May 2019).

Opening the pre-salt to foreign operators, instead of Petrobras as sole operator, was a 2016 change to streamline development of pre-salt reservoirs and attract more investments. To make concession contracts more attractive, the country adopted single-stage exploration; set royalties for new frontiers and mature basins; reduced the minimum net equity for non-operators; and created incentives to increase investment.

New E&P policies were issued to optimize recovery; quantify oil potential; intensify exploration; and promote proper monetization of existing reserves. Government programs were devised to revive onshore areas, and develop internal markets.


With these initiatives in place, and presaged by success in earlier bidding rounds, the 2019 sales were eagerly anticipated. The four licensing rounds opened with the first Open Acreage cycle on Sept. 10, followed by Concession Round 16 on Oct. 10, a Transfer of Rights Round on Nov. 6, and Production Sharing Round 6 on Nov. 7.

Bidding generally failed to meet expectations across a broad scope of properties. Industry wisdom pointed to a number of culprits, from large signing bonuses and complex regulations to a simple lull, as majors digested recent acquisitions.

The start of the Open Acreage cycle awarded 33 exploration blocks and 12 marginal fields out of 273 production and exploration concessions, Fig. 3. Signature bonuses totaled $5.5 million. But three shallow-water blocks in the Campos basin and five deepwater blocks in the Sergipe-Alagoas basin raised eyebrows, when they failed to garner any bids. ANP had expected to receive at least one bid for each of the sectors that were nominated for the sale. One of the bright spots was the ExxonMobil-Enauta-Murphy Oil acquisition of three ultra-deepwater concessions in the Sergipe-Alagoas basin for $1.9 million.

Open Acreage is a continuous offering of relinquished marginal oil fields and exploration blocks offered in past bid rounds that were not awarded or had been transferred to ANP. In addition to offshore, it offers onshore concession not included in bidding rounds. ANP has expected the program to play a key role in boosting production and recovery rates, especially onshore and in mature offshore basins.

Round 16 produced $2.2 billion in signing bonuses. Still, only 12 of 36 blocks were bid—all in the prolific Campos and Santos basins. ANP anticipates the sale will ultimately result in an exploration investment, upwards of $380 million.

Despite the dollars invested, enthusiasm was less than anticipated. After the sale, Wood Mackenzie researcher Juliana Miguez observed that “The Majors and Petrobras look to be keeping their powder dry” for the two upcoming rounds.

In Round 16 bidding, Petrobras won one block with BP and was outbid for Block CM-541 by a group consisting of Total, Petronas and Brazil QPI, which paid a record $1 billion. Other company and group winners were: Petrobras and BP Energy (Block-477); Shell, QPI and Chevron (Blocks CM-659 and CM-713); ExxonMobil (Block CM-479); Petronas (Blocks CM-661 and CM-715); Repsol (Block CM-795); Repsol and Chevron (Block CM-825); and Chevron, Wintershall Brazil and Repsol (Block CM-845).

In the Santos basin, the Chevron-led group acquired Block SM-766, and BP Energy won Block SM 1500.

In November, the much-anticipated Transfer of Rights (TOR) round, promoted as Brazil’s largest oil license auction, did not deliver as expected. Only two of the four blocks offered in the surplus auction were awarded. They both went to Petrobras. In the first, a consortium with Chinese companies CNODC and CNOOC (each with a 5% interest) won Bruzios field, which is producing about 600,000 boed. Petrobras was alone in its bid for the Itapu Block. The remaining Sepia and Atapu areas received no bids.

Energy Analytics Institute called the TOR round a “huge disappointment,” and said authorities misjudged the market and got the terms wrong. The cost of entry was too high and compensation too complex and uncertain, with government pricing assets as fully developed and with little risk.

The government said it would reexamine the auction results and consider alternative sales. “We will analyze why the big firms did not participate” and study different options for reoffering the Atapu and Sépia areas, said Energy Minister Bento Albuquerque.

Petrobras CEO Roberto Castello Branco also noted the lackluster showing and said the company expected more competition in the bidding. He observed that “Brazil has many complexities in the regulations for the oil industry and I hope they are eliminated. This country needs to be more simple.”

The TOR was established during the 2010 Petrobras share offering, when Brazil traded extraction rights in the area, in return for a controlling number of Petrobras shares. As the fields became commercial, the two began renegotiating contracts. In April, they cut a $9-billion deal, but details about how winners in the TOR bid round would partner with Petrobras remained unclear, according to a Reuters report.

Held a day later, the 6th pre-salt production-sharing contract (PSC) round was generally expected to be more positive and competitive, following on the heels of the weak TOR results.

That optimism was not well-rewarded. The round offered four Santos basin pre-salt blocks and one in the Campos basin. Of the record 17 companies registered for the auction, only Petrobras acquired property—in the Aram Block.

The low engagement may be due to several factors, said Wood Mackenzie researcher Juiliana Miguez. They include a dry well at the Peroba deepwater block, awarded in PSC Round 3 in 2017. In addition, on the heels of holdings added since the 2017 rounds, majors may not be interested in fresh acreage right now. Regulatory overhead also may have played a factor in the lackluster bidding.

Planned for 2020 and 2021 are the 7th and 8th pre-salt production sharing rounds. Round 7 in 2020 involves the Esmeralda and Agate areas, located in the Santos basin, and Água Marinha, located in the Campos basin, Fig 4.

Round 8 in 2021 is for the Tupinambá, Jade and Ametista areas in the Santos basin, and Turmalina in the Campos basin. Round 17 concession bids are planned for 2020, and include blocks in the Pará-Maranhão maritime basins, Pelotas, Potiguar and Santos. Concessions also are planned for Round 18 in 2021.


Petrobras. Activity in the closing months of 2019 and early 2020 shows Petrobras actively divesting properties and interests. In January, the company announced that it would sell its entire stake in two sets of deepwater post-salt offshore concessions—the Golfinho and Camarupim Clusters—in the Espírito Santo basin. The Golfinho Cluster is comprised of Golfinho oil field, Canapu gas field and the BM-ES-23 exploratory block. Average total production from the fields between 2018 and 2019 was 15,000 bopd and 750,000 cfd.

The Camarupim Cluster is comprised of the unitized Camarupim and Camarupim Norte fields, both producers of non-associated gas. Operator Petrobras has a 100% stake in the Golfinho and Camarupim concessions, with the exception of the BM-ES-23 exploratory block, in which it holds 65%.

Petrobras and Malaysia’s Petronas concluded a $1.293-billion deal in late December for 50% of E&P rights in Tartaruga Verde field (concession BM-C-36) and Module III of Espadarte field. Petrobras will keep 50% and operate the fields. Tartaruga Verde field began operations in 2018, and current production is about 103,000 bopd and 1.2 MMcmd. The Module III area is planned for development with Tartaruga Verde field, and Petrobras expects first oil in 2021.

Petronas Executive V.P. and Upstream CEO Adif Zulkifli said, “The completion of the acquisition of Tartaruga Verde and Module III of Espadarte, as well as the three exploration blocks won in the recent bid rounds in Brazil, is testament to Petronas’ steady progress in expanding our oil business in South America.”

Petrobras and Total announced that they will offer interests in the deepwater BM-P-2 concession in the Pelotas basin, offshore Rio Grande do Sul State. Each has a 50% interest; Petrobras won the concession in ANP’s 2004 6th bidding round, and Total’s acquisition was in 2013. Petrobras said the concession “presents a reduced exploratory commitment with the potential to prove significant volumes and establish a position in a new exploratory frontier.”

Onshore, Petrobras is preparing to sell its interest in two concessions in the state of Amazonas. The current binding stage includes proposal guidelines. The Cupiuba and Carapanauba Cluster in the Espírito Santo basin averaged production in 2018 of about 81 bopd and 82,000 cmd.

Petrobras sold its entire stake in 34 onshore production fields located in the Potiguar basin, in the state of Rio Grande do Norte, to Potiguar E&P S.A., a subsidiary of Petrorecôncavo S.A. The Dec. 9 transaction was completed with the payment of $266 million on top of a deposit of $28.8 million. In addition, a payment of $61.5 million is conditional on extending the concession term for 10 of the 34 concessions.

The fields are onshore in the Potiguar basin, in the state of Rio Grande do Norte. They produced an average 5,800 bopd in 2019. All concessions are 100%-owned by Petrobras, except for Cardeal and Colibri fields, where Petrobras holds a 50% stake with Partex Brasil Ltda. as operator, and Sabiá da Mata and Sabiá Bico-de-Osso fields, where Petrobras has a 70% stake.

Petrobras also plans to sell its 50% interest in the onshore fields of Dó-Ré-Mi and Rabo Branco, in the BT-SEAL-13 Concession, in the Sergipe-Alagoas basin.

Shell, an historic player in Brazil, announced in November that new, deepwater production has come online in the pre-salt Santos basin. Shell (25%) and consortium partners Petrobras (operator, 42.5%), Total (22.5%) and Petrogal (10%) started oil and natural gas production at the P-68 FPSO in the BM-S-11-A (Iara) concession in Berbigão, Sururu and West Atapu areas, Fig 5. The P-68 can process up to 150,000 bopd and 6 MMcmd from 10 producing wells and seven injection wells.

Development in Iara opens a new production frontier in the pre-salt, said Shell. It is also the first step in developing Sururu. The two blocks awarded to Shell in the 16th concession deepwater bid round were the latest additions to a Brazil portfolio of 2.6 million net acres with 21 exploration blocks, four development fields and 11 production fields.

ExxonMobil. Leading a consortium with Enauta (30%) and Murphy Oil (20%), ExxonMobil acquired three ultra-deepwater oil and gas concessions during the open acreage auction.The companies paid $1.9 million for the SEAL-M-505, SEAL-M-575 and SEAL-M-637 Blocks in the offshore Sergipe-Alagoas basin. The three blocks are close to areas that the consortium won at recent offshore bidding rounds and near Petrobras discoveries. Exxon Mobil has more than 2.3 million net acres in Brazil.

Equinor. In December, Equinor announced the commercial viability of two blocks licensed in the pre-salt Santos basin, Carcara oil field. Equinor is the operator with partners ExxonMobil and Petrogal Brasil in the BM-S-8 and Norte de Carcara licensed areas. Four of five exploratory wells drilled produced oil.

In December, the topsides for Equinor’s Perigrino C platform arrived from Ingleside, Texas, for the Campos basin installation. Peregrino field in the Campos basin has been the company’s largest operated international platform.

About the Authors
Mike Slaton
Contributing Editor
Mike Slaton is a contributing editor.
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