The current year has brought a renewed sense of investor confidence to Latin America’s major upstream markets. Investment in the region had been hit hard since 2014 by the drop in global oil prices as well as political and institutional crises that were in motion before prices fell. Fiscal and regulatory burdens on industry, financial constraints of state energy companies, and uncertainties around domestic resource pricing were already present in countries such as Mexico, Brazil and Argentina. Combined with more disciplined capital budgets from oil companies during a lower price environment, the result was a diminished appetite for investment in those markets. But the mood has started to shift. Governments in Latin America have been putting in place regulatory reforms to incentivize greater investment in their respective oil sectors. Those changes have begun to bear fruit in 2017.
The Great Recovery of Mexico
The past 12 months have kick-started Mexico’s oil industry. Well before the collapse in prices, the government of President Enrique Peña Nieto passed sweeping reforms to overhaul the country’s energy sector and allow the participation of private investment. Production by state energy monopoly Petróleos Mexicanos (Pemex) had dwindled from its peak of 3.4 million barrels per day in 2004 to just above 2 million barrels per day when the reforms were approved in 2013, underscoring the need for private operators to reverse those declines. Initial auctions for exploration and production licenses held in 2015 drew limited interest from foreign investors as industry was still adjusting to the new price realities. But a tide of investment began in earnest with Mexico’s first auction for deepwater blocks in December 2016. Considered the "crown jewels" of Mexico’s upstream assets, the deepwater round generated heavy interest from international majors. Chevron, ExxonMobil, Total and BP all picked up acreage through a variety of consortia. So too did international firms such as Statoil, INPEX, and Petrobras. China National Offshore Oil Corporation (CNOOC) picked up two blocks as a stand-alone investor, breaking a tradition that saw China’s national oil companies typically participate through upstream consortia across Latin America. In addition to eight of the ten deepwater blocks on offer being awarded, BHP Billiton won a 60 percent interest to co-develop the Trion Deepwater field in partnership with Pemex. The alliance marked the first deepwater farm-out undertaken by Pemex. All told, the assigned contracts licensed in the deepwater round carry an associated investment of approximately USD 34.4 billion over the next 35 years, according to Mexico’s energy ministry. The greatest returns from the round, however, will likely come from the wider ripple effect across the Mexican oil sector and the degree of confidence that oil majors have vouched for in Mexico. The Mexican state will receive, on average, between 60 and 66 percent of the profits generated from the awarded contracts. According to Mexico’s government, the 10 blocks originally offered contain almost 11 billion barrels of oil-equivalent resources. Juan Carlos Zepeda, head of Mexico’s National Hydrocarbons Commission (CNH), estimated that the areas awarded in the deepwater auction could eventually add up to 900,000 barrels per day to Mexico’s oil production. Investor interest in Mexico’s offshore continued in June of this year when CNH licensed 10 of 15 shallow-water blocks on offer in a subsequent auction. Associated investments for those blocks could reach USD 8.2 billion and add an additional 170,000 barrels per day of crude oil equivalent to the country’s production. Resurrecting Mexico’s energy production was one of the foremost aims of the reforms. Huge strides were taken towards that objective in July with the announcement of major offshore discoveries. While licensed acreage in offshore auctions represent potential finds, two large confirmed discoveries announced by Talos Energy and Eni are, to date, the most successful materialization of Mexico’s energy reforms. The first discovery, a find by a consortium comprised of Houston-based Talos Energy, local Mexican outfit Sierra Oil & Gas, and Premier Oil of the United Kingdom, has been touted as one of the largest shallow-water oil discoveries in the world over the past 20 years. Talos, who operates the block in the Gulf of Mexico off the coast of Tabasco state, reported that the field it discovered holds between 1.4 and 2 billion barrels of oil in place-multiples of its original estimates. Under current prices the discovery equates to around 500 million barrels of potentially commercial reserves. The same day that Talos reported its find, Eni announced that it had struck yet more oil on a previous discovery offshore Mexico and was upping its reserve estimates for the field. The shallow-water Amoca field, Eni notes, now holds at least 1.3 billion barrels of oil equivalent in place, with around 90% being crude oil. To be sure, the precipitous drop in Mexico’s oil output over the past 13 years means that the country still needs many more bid rounds that yield additional large-scale discoveries to recoup its previous production levels. According to Mexican energy experts, the country needs about another 10-15 more bid rounds like the December 2016 deepwater auction and around an additional 11 billion barrels of proven reserves to be continually developed to come close to its 2004 output volumes. Fortunately for investors, there is still much more for the taking. The Mexican state has so far awarded just 10 percent of the total 2P reserves (Proven + Probable Reserves) that have been earmarked for public auction, or just 273 million of a total 2.8 billion in proven and probable reserves. Much of what remains will be licensed in a series of bid rounds that have been scheduled for the next five years. The government has identified 509 exploration blocks and 82 production fields that will be put to bid over that time period, providing investors a consistent timetable of what’s to come in Mexico’s upstream.
From Brazil, signs of greater consistency and guarantee
Brazil too has ushered in a stronger sense of consistency and security for investors that has begun to realize returns in 2017. Unlike Mexico, reforms that Brazil’s government enacted for its oil sector came about after the fall in global oil prices. The makings of the reforms were in motion well before the price drop, but the decline in prices compounded the need for change. The "Operation Car Wash" scandal that has ensnared Petrobras has forced the state-owned oil company, and by consequence, much of Brazilian industry to shift course. The financial fallout from corruption probes, class-action lawsuits, and credit downgrades amplified the company’s tenuous footing as the most heavily indebted oil company in the world, with close to USD 120 billion in outstanding debt. As a result, the company launched an aggressive divestment program to raise cash and spin-off non-core assets. Petrobras’s five-year business plan for 2014-2018, for example, aimed to invest USD 220 billion. Its current plan covering the 2017-2021 period now stands at just USD 74 billion. Over the next two years, Petrobras is has a divestment plan totaling USD 19 billion. For Petrobras non-core assets essentially constitute anything outside of its offshore pre-salt portfolio. Foreign upstream holdings and domestic natural gas infrastructure are particularly open for outside investment, and Petrobras has already divested billions of dollars of these assets. But even Petrobras’s once-dominant hold on pre-salt acreage is more open to outside investors. To alleviate the company of its financial obligations, the Brazilian government reversed a law in November 2016 which previously required Petrobras to hold a minimum 30 percent operator stake in any pre-salt acreage that would be licensed in future. Given the scale of Brazil’s pre-salt formations, removing that mandate frees up Petrobras from billions of dollars of development obligations. The opening of the pre-salt coupled with Petrobras’s divestment program are being described as the most significant changes in Brazil’s energy industry since the formation of Petrobras in 1953. To further incentivize upstream investment, the Brazilian government has also eased local content requirements for future bid rounds, established separate royalties for new frontier areas to incentivize exploration risk, and renewed a crucial "Repetro" customs regime that provides tax benefits for industry. All of these policies conform to President Michel Temer’s more market-oriented agenda to stimulate private investment more broadly across Brazilian industry. And they are now being put to the test. Last month Brazil hosted its first major upstream auction since December 2015 and the passing of these new reforms. While just 13 percent of the 287 blocks on offer were issued license, the tender drew more than USD 1.2 billion in signing bonuses—the highest ever sum for an oil and gas auction in Brazil. Like recent offshore rounds in Mexico, the caliber of upstream participants represented a vote of confidence in Brazil’s upstream market attractiveness. Most notably, the auction saw ExxonMobil vastly expand its presence in Brazil. The U.S. major picked up ten blocks through the course of the auction-six in a consortium with Petrobras. Prior to September, ExxonMobil had only a marginal presence in Brazil’s upstream, owning a few blocks in the country’s northern equatorial margin. In contrast, other major international oil companies such as Chevron, Royal Dutch Shell, and Statoil of Norway have long staked Brazil as a core piece of their global activities. ExxonMobil’s 50-50 consortium with Petrobras resulted in the lion’s share of signing bonuses pledged. The companies offered up a combined USD 1.13 billion in signing bonuses, equal to 93 percent of the auction’s total. The two firms also presented the single largest bonus for one area-roughly USD 700 million for a Campos Basin block. Bidding was fierce among the high-profile industry investors: one sum offered by ExxonMobil and Petrobras was five times higher than the runner-up’s bid. Another was more than 25 times the second-place consortium of BP and Total. All told, the signing bonuses pledged were more than double the amount that the government anticipated it would collect for the auction. Other big winners included China’s state-owned CNOOC and Spain’s Repsol, which picked up offshore blocks for USD 7.4 million and USD 7.2 million respectively. In addition to its vindication for market reforms, the auction also serves as an early gauge of interest for two pre-salt bid rounds that the government will host on October 27. The average productivity of a pre-salt well in Brazil’s Santos Basin ranges between 20,000 and 40,000 barrels per day and have among the industry’s lowest break-even costs. The biggest names and most experienced operators in the global oil industry are registered to bid in what is surely one of this year’s most highly anticipated licensing rounds.
Argentina's enger future, the Vaca Muerta shale formation
Further south from Brazil, arguably the world’s most attractive onshore play is picking up steam. Argentina’s Vaca Muerta shale formation is described as the most commercially attractive shale play in the world outside of the U.S. and the epicenter of deal activity in Latin America. Around half a dozen pilot projects in Vaca Muerta are set to transition to commercial development in the next two to three years. Oil output is projected to roughly double from 58,000 barrels per day this year to 118,000 barrels per day in 2019, with natural gas volumes more than tripling over that same period. International investors who have long been skittish about investing in Argentina appear to be growing more confident in the pro-business policies of President Mauricio Macri. Neuquen province, where most Argentina’s prolific Vaca Muerta shale play is concentrated, has begun to see a steady increase in upstream investment. The province drew USD 3.2 billion in investment last year-the lowest total since 2012-but projected investment for this year will be between USD 4.5 and 5 billion. The main reason for the uptick is a federal shale gas price incentive announced earlier this year. Under the agreement gas producers earn USD 7.50 per million Btu through the end of next year-a subsidized price that is more than double the U.S. Henry Hub benchmark. Several companies have responded to the program with major new investments. The most significant new commitment has come from Tecpetrol, which plans to spend USD 2.3 billion to produce as much as 10 million cubic meters per day of gas in the Fortin de Piedra Block. Total announced in April that it would invest USD 1.1 billion to develop the Aguada Pichana Este Block alongside Argentina's state-controlled YPF, Wintershall, and a local BP affiliate. Vaca Muerta developments are still largely led by YPF, which operates the only two development projects undertaken so far. The biggest is a joint venture with Chevron in the Loma Campana area which went into development mode in 2014. A smaller, gas-focused project with Dow Chemical is underway at El Orejano. As experience and learnings of the Vaca Muerta proliferate, drilling costs will lower and that will create positive synergies for even greater investment. Costs have already come down sharply. According to YPF, average drilling costs for a horizontal well with around 19 frack stages was USD 8.1 million. That cost compares to last year’s average of USD 10.5 million for a well with 17 frack stages. The backdrop of low oil prices for industry is still very important and remains the principal driver for subdued investment activity across the global oil and gas landscape. But so far, 2017 has offered encouraging signs of an uptick in investment in Latin America as a result of market reforms put in place by three of the region’s largest countries.