Is the fragile market cracking under pressure? Despite some ambitious growth-oriented investments, some of the continent’s traditional big guns will be facing challenges in 2019
Despite rising crude prices in 2018, many Latin American countries are still grappling with considerable debt and declining production rates. However, recent discoveries and licensing rounds have attracted a strong uptick in foreign investment, which could be the region’s key to economic resurgence.
Due to high inflation and declining production, Argentina is putting forth an effort to counteract the deterioration of its E&P sector. Since its 2001 default, caused by a severe economic recession, Argentina has worked to escape its financial crisis. The country, home to abundant shale reserves, has gone from a chief net exporter to a net importer of gas in recent years. To keep its energy industry above water, the government is promoting development of complex reservoirs.
Argentina’s largely undeveloped Vaca Muerta shale is said to hold upwards of 16bn barrels of oil and 308tr cf of recoverable gas. The unconventional shale formation covers a very large area within the Neuquén basin. After numerous incentives were proposed by President Mauricio Macri in an effort to reduce the high cost associated with development of unconventional wells, international oil majors and investors are showing more interest in the region.
In 2017, Wintershall launched its second operated pilot project, spudding the first of three horizontal pilot wells in the Bandurria Norte Block, in western Neuquén. According to the company, its operations had, until now, been focused primarily on conventional reservoirs as a non-operator. The company, alongside partner GeoPark Limited discovered a new oil field in August 2017. GeoPark reported that early production tests showed a flowrate of 300bl/d and de-risked other delineated light oil prospects in the block.
Several majors have partnered with state-owned YPF to explore the coveted shale formation. Statoil and YPF entered an agreement to explore the Bajo del Toro Block of the Neuquén basin. Holding 50pc each, the companies will jointly explore the 38,800-acre block in Argentina’s western region. Equinor (formerly Statoil) was subsequently awarded the Bajo del Toro Este exploration license, situated east of Bajo del Toro.
Additionally, majors are backing a $1.15bn investment in the Vaca Muerta formation, after the provincial government divided the Aguada Pichana area into two sections and combined it with the Aguada de Castro area. YPF, Total, Wintershall and Pan American Energy agreed to the joint investment, which has Total operating the eastern part of Aguada Pichana with a 41pc stake, while BP unit Pan American Energy operates the western part, as well as Aguada de Castro, with a 45pc stake.
ExxonMobil is another active oil major in Argentina’s Neuquén basin. The company says that it has invested more than $500mn in the exploration and development of its Vaca Muerta assets since entering the region. In October 2017, it announced that its investment plan for the development of resources in the Los Toldos South Block, northwest of Neuquén City, had been granted government approval. The initial $200mn investment funds a pilot project that should put seven wells into production. It also will support construction of production facilities and associated export infrastructure.
President Energy—which holds a working interest and is the operator in the Puesto Flores and Estancia Vieja concessions, as well as the Puesto Guardian license and two exploration areas surrounding it—announced significant upgrades to its prospective resources in November 2017. The results of an integrated basin study and geochemical survey showed aggregate Paleozoic gas/condensate prospects net to the company with mean unrisked prospective resources (MUPR) of over 7tr cf, with an upside case of over 20tr cf and 185mn bl of condensate. Additionally, results showed previously unreported Cretaceous oil prospects of over 40mn bl, MUPR.
In early 2018, the company reported that its Neuquén basin 2P net reserves had increased 66pc, from 4.82mn boe to 8mn boe, while its 1P reserves increased more than 30pc, from 3.2mn boe to 4.5mn boe, since the assets were acquired. The success is a direct result of a successful four-well workover program at Puesto Flores. The company said that it expects further upgrades in reserves under its 2018 capex programme.
Although it has some of the world’s largest oil and natural gas reserves, Venezuela has failed to retain its status as a top oil exporter in the Americas. Since President Nicolás Maduro took office in 2013, production has tumbled. The situation deteriorated further in 2018, falling from 2.15mn bl/d to 1.25mn bl/d in Q3 2018. The country’s production decline is now five times greater than the amount it pledged to cut in the October 2016 Opec deal.
Until recently, production of extra-heavy crude from the Orinoco Belt was helping to keep Venezuela’s industry afloat. The belt, which is in Venezuela’s Guárico state, overlies some of the world’s largest petroleum deposits. Nevertheless, by the end of 2017, Orinoco output had fallen to a reported level of 882,000 bl/d-a decline of more than 300,000 bl/d from the year prior.
The drop in production could, in part, be due to reports that the quality of Venezuelan oil has been waning, as well. Refiners in the US and Asia have reported issues in crude quality, including high salt and water content. In some cases, buyers have turned away cargoes entirely.
Additionally, PDVSA’s operational and cash-flow issues continue to prevent the company from climbing out of debt. Although the company made multi-billion-dollar debt payments late in 2017, it reportedly still owes millions. To shore up its economy, Venezuela introduced its own commodity-backed cryptocurrency early in 2018. According to the government, each “petro” is backed by a barrel of oil and is sold at the same price. Despite the reservations of many, President Maduro said that the petro is sure to be “a total success for the welfare of Venezuela.”
PDVSA has ambitious plans for the future, however, and says it wants to increase Venezuelan crude production to about 6mn bl/d by 2019, of which 4mn bl/d are anticipated to come from the Orinoco belt. Additionally, the company’s national plan calls for a significant boost in natural gas production, up to 10.5bn cf/d by 2019. Also by 2019, it hopes to reach an export goal of 1.3mn bl/d to Latin America and the Caribbean, and 3.2mn bl/d to Asia.
While much of Latin America’s energy sector is struggling, Brazil’s pre-salt layer remains a hotspot for explorers. The attractiveness of pre-salt blocks in the deep waters of the Campos and Santos basins helped bring in billions during the country’s latest licensing round. In late October 2017, key E&P players, including Shell, Equinor and ExxonMobil, won production sharing contracts (PSCs).
As Latin America’s largest country, Brazil’s influence on the future of the international energy marketplace continues to grow. International Energy Agency (IEA) Executive Director Fatih Birol highlighted the country’s “determined and ambitious long-term energy policies, developing deep-water oil resources and expanding biofuels output” as setting an example to countries around the world. According to IEA, Brazil is on track to be a net exporter of nearly 1mn bl/d by 2022. This results from a reported 50pc increase in oil production over the last 10 years, which can largely be accredited to the country’s budding deep-water sector.
Libra, one of the world’s biggest deep water discoveries, began producing in November 2017. Soon after, the Libra Consortium—made up of Petrobras, Shell, Total, CNOOC and CNPC—affirmed commerciality of the oil accumulation in the northwestern section of the block, calling it Mero field. According to Petrobras, the newly-named field has an estimated recoverable volume of 3.3bn bl of oil. Plans for the development of Mero field, off the coast of Rio de Janeiro in the Santos basin, include four new production systems. According to Total, Libra production should reach more than 600,000 bl/d in the coming years.
Equinor tripled its production in Brazil late in 2017, with the acquisition of a 25pc interest in Roncador field in the Campos basin. The field is Petrobras’ third-largest producing asset, with approximately 10bn boe in-place, and an anticipated remaining recoverable volume of over 1bn boe.
During Brazil’s 15th licensing round, Equinor, with several major partners, further strengthened its position in the deep waters of Brazil with winning bids for four blocks-C-M-755, C-M-657, C-M-709 and C-M-793-in the southern part of the Campos basin. Other key players, including Shell and ExxonMobil, also won deep-water blocks during the licensing round. Wintershall, however, bolstered its position in a big way, becoming the country’s fourth-largest producer with newly-awarded interests in seven licenses.
In April 2018, Petrobras reported the start of production at Bùzios field, one of its principal pre-salt projects. It said the field’s potential for high output is cause for the four additional platforms that are planned through 2021.
Following a series of major discoveries by ExxonMobil, Guyana has become a highly sought-after region for explorers. As yet, Guyana has not been an oil producer. However, Wood Mackenzie says it anticipates that the country will be one of Latin America’s top producers by 2026, with an estimated output of approximately 350,000-to-400,000 bl/d.
ExxonMobil’s Liza development, which holds resources between 2bn boe and 2.5bn boe, reached a final investment decision in June 2017. The first phase of development will include a subsea production system and an FPSO vessel capable of producing 120,000 bl/d. The field is expected to start producing by 2020.
ExxonMobil reported more success offshore Guyana in July 2017, when its Payara-2 well encountered 59 ft of high-quality, oil-bearing sandstone, confirming a second giant field in the Stabroek Block. The positive well results increased Payara field’s estimated resources to approximately 500mn boe.
By October 2017, ExxonMobil had struck its fifth discovery offshore Guyana. The company’s Turbot-1 well encountered 75 ft of high-quality, oil-bearing sandstone within the southeastern part of the Stabroek Block.
In January 2018, Exxon’s sixth Stabroek Block discovery was reported. The Ranger-1 exploration well encountered about 230 ft of high-quality, oil-bearing carbonate reservoir, after it was drilled to a depth of 21,161 ft in 8,973 ft of water.
E&P activity in Mexico has seen a dramatic decline of late. Energy reform in Mexico, however, has ended a 75-year state monopoly in the oil and gas sector, and shifted the nation’s attention to attracting private capital and technical expertise that could help rebuild Mexico’s ailing economy.
During the 2018 CERAWeek in Houston, Pemex CEO Carlos Treviño said that “the new name of the game, for Pemex, is ‘partnerships.’ Through an aggressive farm-out strategy, the company aims to lure foreign investment through a series of asset auctions that will, with any luck, help reverse the country’s output decline.
In January 2018, Mexico awarded 19 deep water blocks to oil majors, including Shell and Eni, reportedly bringing in billions of dollars’ worth of investment. In March, Mexico offered 35 shallow-water areas, which was due to be followed by an auction for 37 onshore developments in July.
Emily Querubin is Associate Editor, World Oil