BP, Pan American Eye Exporting Argentina Shale Gas As LNG Via Chile

(S&P Global Platts, 15.Nov.2018) — Pan American Energy, the second-biggest oil producer and third for gas in Argentina, is working with BP on potentially exporting LNG out of Chile, a project that could prove faster to get Vaca Muerta shale gas to market than building a liquefaction facility in Argentina.

The project is in the conceptual design phase and would involve delivering supplies over an existing Argentina-Chile pipeline to the Quintero LNG regasification terminal in Chile, said Alejandro Lopez Angriman, vice president of reserves development at Pan American.

The Quintero terminal “can be turned around so it can liquefy to export,” he said on the sidelines of an energy conference in Mendoza, Argentina.

The pipeline has 10 million cu m/d of capacity for moving supplies from Vaca Muerta to Chile, but is mostly running empty. It has been used over the past few June-to-August winters to bring regasified LNG to Argentina from Chile.

To deliver supplies to Chile, the pipeline would have to be modified with a loop, Lopez Angriman said.

BP — which owns 50% of Pan American alongside Bridas, itself 50% owned by China’s CNOOC — is helping on the conceptual engineering for the project, he added.

The project could cost around $300 million if it goes forward, he added, with the first train exporting 25 million cu m/d.

LOOKING FOR NEW MARKETS

The research into the project comes as gas production surges in Argentina, led by Vaca Muerta, one of the world’s largest shale plays.

The country’s overall gas production rose 14% to 130 million cu m/d this year from a 16-year low of 113.7 million cu m/d in 2014, allowing the country to restart exports by pipeline to Chile after an 11-year suspension.

The Energy Secretariat estimates that with enough investment Vaca Muerta could double the country’s gas production over the next five years to 238 million cu m/d, allowing exports to surge to 100 million cu m/d in 2023 from less than 1 million cu m/d this year.

In the late 1990s and early 2000s, Argentina exported 20 million cu m/d to Brazil, Chile and Uruguay, and the pipelines are still in place. The country halted exports in the mid-2000s as production plunged, bringing shortages and a surge in imports of Bolivian gas and LNG. Imports have averaged 30 million cu m/d since 2012, but started declining this year, according to Energy Secretariat data.

Pan American got a permit this year to export gas to Chile, and it likely will start to make deliveries during the upcoming December to February summer for consumption in that market, Lopez Angriman said.

But he said that won’t be enough to sustain a larger development of Vaca Muerta, where he estimates one field could easily supply the LNG export terminal.

“The field could produce 25, 50, or even 100 million cu m/d,” Lopez Angriman said. “It’s incredible the number of wells that you can do in Vaca Muerta for gas.”

Frackers, he added, have de-risked the gas potential in Vaca Muerta, and the next step is to find the capital to put it into full-scale production. But to attract investors, more pipelines are needed to get the gas out and additional markets must be found to increase sales so production can be sustained year-round, not slowed during the summer with the closing of wells. State-run YPF, the country’s biggest gas producer, had to close gas wells in the third quarter of this year, in part because warming temperatures and a contracting economy reduced demand.

Argentina has sharp fluctuations in gas demand, from 115 million cu m/d in the summer and peaks at 180 million cu m/d in the winter, according to data from Enargas, the national gas regulator.

“It is not a good thing to convince investors to invest in shale gas when production has to be halted during the summer,” Lopez Angriman said.

CUTTING WELLHEAD COSTS

While gas exports can be increased to neighboring countries, these markets suffer the same predicament as Argentina: their demand for gas plunges in the summer. That means LNG must be pursued if output from Vaca Muerta is to be expanded, he said.

But to do that, a big challenge is to bring down development costs in the play so the gas can be competitive against Australia, Qatar, the US and other suppliers in sales to Southeast Asia, where demand is expected to grow, Lopez Angriman said.

He estimates that at around $3/MMBtu, sales can be competitive. But to get there, Vaca Muerta development costs must come down 30%, and the focus is on easing the strain of frack sand, which accounts for 30% of the well completion cost, he said.

Frackers have shaved the cost of sand to $190/mt from $250/mt over the past few years, but it is still higher than the $60/mt figure in the US.

“If we are going to compete with the US or Canada, one way or another we have to reduce the cost of sand,” he said.

Help is to come from moving more sand by boat and train to Vaca Muerta, located in the southwest. Most of the sand is currently being trucked 1,000 km (621 miles) from Entre Rios, a central province, with transport accounting for 50% of the total cost of sand.

There is a government-led plan to extend a cargo railway to Vaca Muerta, but it is not likely to start for three to four years. Once it is in operation, the cost will come down because it is cheaper to move the sand from Entre Rios by river and ocean to Bahia Blanca, an Atlantic port where it can be loaded onto the train for delivery to the well sites.

THE ARGENTINA LNG OPTION

Pan American also is looking at the option of building liquefaction capacity in Argentina, as are other companies.

On Monday, YPF said it plans to install a floating liquefaction barge in Bahia Blanca to export up to 2.5 million cu m/d of LNG from 2019, and then work on building a larger export terminal.

The government, meanwhile, is studying a project for exporting LNG from a six-train onshore terminal in Bahia Blanca, likely starting in 2023 with shipments of 40 million cu m/d, increasing to 120 million cu m/d in 2025.

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Venezuela, Mexico Divert Crude To U.S. As Canadian Barrels Get Stuck

(Reuters, Marianna Parraga, Collin Eaton, 26.Oct.2018) — Cash-strapped state-run oil companies in Mexico and Venezuela have begun diverting crude historically processed for domestic use and sending it to U.S. refiners now facing transportation constraints to secure similar grades from Canada, data shows.

The situation reflects an unusual set of events, including urgent needs by Venezuela and Mexico for cash for debt payments and investment, and demand for heavy crude in the United States due to less availability of Canadian oil, said traders and analysts.

The United States imported 1.675 million barrels per day (bpd) of Latin American crude in August, the highest level since May 2017, according to Refinitiv Eikon data.

That gain occurred even though the preferred Latin American grade, Mexican Maya, fetches an about $50 a barrel premium to Western Canadian Select (WCS), because of transportation costs. Moving a barrel of Maya via tanker to the U.S. Gulf Coast costs about $1.50, compared to $35 for WCS via pipeline and rail.

“Those who are arriving late to the (Canadian oil) party will have to pay more for a Latin American heavy crude or Iraqi Basrah Heavy,” said a trader who regularly buys Canadian and Latin American grades.

CASH NEEDS RISE

Latin America’s recent export drive has come mostly from Mexico, Brazil and Venezuela, despite a long-standing regional oil output drop. In the last decade, suppliers with the exception of Brazil have reduced crude shipments overall, especially to the United States.

In the case of Venezuela, state-run PDVSA “needs cash both for paying holders of the 2020 bond this month and for paying (an arbitration award to) ConocoPhillips,” said Robert Campbell, oil products research chief at consultancy Energy Aspects, referring to two huge bills due in coming days.

Petroleos Mexicanos is raising cash mainly for refinancing its heavy corporate debt. Selling more of its coveted Maya crude could help refurbish refineries working at historically low rates.

Pemex and PDVSA did not respond to requests for comments.

Before the shale boom, many U.S. Gulf Coast refiners configured their plants to run Latin American and Middle Eastern crudes, with Venezuela and Mexico as top suppliers. As those shipments dwindled, refiners turned to shale and Canadian oil.

But pipeline constraints in Canada are shifting imports again, at least in the short term.

U.S. refiners want more Canadian crude “because it’s cheap,” one trader said, but “unless someone builds a new pipeline,” it will be difficult boost imports further.

U.S. imports of Canadian crude by pipeline rose to 3.6 million bpd in the week ending Oct. 12, hitting 98 percent of capacity. Crude-by-rail shipments also are up, to a record 284,000 bpd in the week ended Oct. 12 from 85,000 bpd in October 2017, according to data provider Genscape.

“These pipelines are absolutely full,” said Dylan White, an oil markets analyst at Genscape. “There’s no room for growth.”

IMBALANCES

The strategy of boosting crude exports while importing more fuel could backfire for Latin sellers. Pemex would have to boost fuel purchases if its refineries do not restart in coming months after outages and unplanned maintenance work, and PDVSA has few options to stop imports from growing.

Latin America has increased U.S. fuel purchases by 7 percent to 2.87 million bpd so far in 2018, lifted by purchases by Mexico, Venezuela, Chile and Peru, according to the U.S. Energy Information Administration.

“Mexico has chosen to import more gasoline. It makes a lot of sense, but it could go out of control,” Campbell said, referring to relatively cheap gasoline prices compared to Latin American heavy crudes.

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Mexico And Brazil’s Crude Politics

(Foreign Policy, Lisa Viscidi, .16.Oct.2018) — A potential return to resource nationalism could set both countries back.

Until this year, resource nationalism—when a government asserts its control over a country’s natural resources—seemed to be on the wane in Latin America. With oil prices low, state oil companies were struggling, and market-friendly governments had started opening their energy industries to private investment.

In the coming months, though, the region’s two largest economies may both have new leaders who came to power on promises of a return to the old days. In Mexico, President-elect Andrés Manuel López Obrador’s vow to restore Mexico’s state energy companies to their glory days and his emphasis on energy independence from the United States were central to his campaign. Similarly, Brazilian presidential candidate Fernando Haddad (who is polling well behind his rival, Jair Bolsonaro, but could still eke out a win later this month) wants to reassert state oil and power companies’ dominant positions in Brazilian energy markets. Both López Obrador and Haddad have argued that the current Mexican and Brazilian governments, in trying to open energy sectors to private investment, have effectively handed over state assets to foreign companies.

This is not the first time Latin American countries have flip-flopped on resource nationalism. The idea was initially championed in the 1950s and ’60s by Juan Pablo Pérez Alfonzo, the Venezuelan oil minister who helped found OPEC, and Getúlio Vargas, the Brazilian president who created the state oil company Petrobras in 1953. The slogan he gave it: “O petróleo é nosso,” or “The oil is ours.”

In the 1990s, historically low oil prices pushed Latin America’s energy sectors toward privatization. Petrobras shares were floated on the São Paulo and New York stock exchanges. Argentina’s state oil company, YPF, was sold off to private investors entirely. Then, in the early 2000s, as oil prices rose again, governments across the region began expropriating energy assets. A wave of recent reforms, again tied to low prices, encouraged private investment once more. In Mexico and Brazil, however, these reforms were never popular. And so, in both countries, the idea of energy sovereignty, part of a broader economic nationalist and protectionist approach, is again taking root.

For his part, López Obrador has long criticized the energy reform that the current president, Enrique Peña Nieto, signed into law in December 2013. That reform revised the constitution to open the oil and power sectors to greater private investment, creating competition for state monopolies. As a presidential candidate, López Obrador condemned the opening as putting the country’s riches into foreign rather than Mexican hands. Now, he wants to strengthen the state oil company, Pemex. He has vowed to increase Pemex’s investment budget to boost oil production, which has plummeted to 1.8 million barrels per day from a peak of 3.4 million barrels per day in 2004. His goal of 2.6 million barrels per day by the end of his term in 2024 is ambitious.

In order to end imports of gasoline from the United States by 2022, another of the president-elect’s goals, López Obrador plans to build a new refinery in his home state of Tabasco and upgrade six existing refineries, which would add over 1 million barrels per day in output if all existing refineries ran at full capacity. Mexico produces mostly heavy crude oil, much of which it ships to the United States for refining. It then imports about 1.3 million barrels per day of refined products back from the United States for domestic consumption. At the same time, López Obrador has promised Mexican voters a decrease in gasoline prices. The Peña Nieto government had cut gasoline subsidies just as international oil prices started to rise again, causing a 20 percent bump in fuel prices.

In the power sector, López Obrador plans to strengthen the state utility company and expand hydroelectric capacity in Mexico to slash imports of natural gas. In recent years, Mexico has become a critical market for U.S. shale gas as the pipeline infrastructure between the two countries has been beefed up. Cheap U.S. natural gas has also lowered the cost of electricity generation in Mexico, so tapering off the imports could hurt on both sides of the border.

In Brazil, the polarizing right-wing candidate Bolsonaro, who won 46 percent of the vote in the country’s first-round presidential election on Oct. 7, will face Haddad, a left-wing candidate from the Workers’ Party, in a second round later this month.

Bolsonaro has said that he is open to foreign investment, privatizing state companies, and creating more competition in oil and gas markets. He would likely push onward with the Petrobras divestment plan that was started under the current center-right president, Michel Temer. As part of that plan, which was designed to reduce Petrobras’s enormous debt, the company has sold off assets in refining, logistics, and transport to focus on its more profitable core business of oil exploration and production. Continued privatization is worthwhile, but beyond his support for it, Bolsonaro has been widely criticized for lacking any specific energy plan or even a detailed economic agenda.

Haddad, meanwhile, is fairly clear in his support for a return to the resource nationalism favored by his fellow Workers’ Party member former President Luiz Inácio Lula da Silva. Following the 2007 discovery of vast deepwater oil reserves, Lula introduced reforms that increased the government’s stake in Petrobras and made the state company the exclusive operator of the new fields. Temer later signed a law that reversed Lula’s bill, creating more opportunities for private investment in the sector. Haddad has promised to reverse Temer’s reversal and recover the oil to benefit the people. He has also pledged to strengthen Petrobras and to support the development of local industries by increasing local content requirements in oil exploitation and production. In short, Haddad would likely look to slow Petrobras’s divestment to keep energy assets in the state company’s hands and reassert its role as a driver of economic development.

Once in office, the new leaders of Mexico and Brazil will inevitably face challenges to implementing many of their plans. It is unlikely that Brazil’s next president will have enough support in Congress to overturn Temer’s law, for example. Likewise, in Mexico, although the president has broad powers to roll back aspects of the energy reform, only a two-thirds congressional majority—which López Obrador is unlikely to secure—can undo a constitutional reform. And in both countries, the administrations would face major legal challenges if they tried to unilaterally change existing contracts with private energy companies.

And then there’s the budget to think of. New refineries cost billions of dollars, are highly susceptible to corruption, and ultimately won’t lower gasoline prices for consumers. Expanding large hydroelectric dams also takes money, and it presents tremendous social and environmental challenges. Forcing a state oil company to operate all exploration and production projects risks massive corporate debt and a credit rating downgrade—precisely what happened to Petrobras under Lula and his successor, Dilma Rousseff. Meanwhile, strict local content requirements that are not coupled with programs to modernize local suppliers merely slow the development of oil and gas reserves. Despite the discovery of the undersea reserves in 2007—one of the most significant oil finds in the world in years—Brazil’s oil production remained nearly flat for years.

State-led development of energy resources can be very successful. Witness Saudi Aramco, the state oil company that has made Saudi Arabia one of the largest oil producers in the world. But experience in Latin America suggests that giving state companies a monopoly over energy production tends to restrict the industry rather than boosting it. And beyond that, it is worth considering whether it is wise to continue depending on oil to float the economy at all. As many other countries around the world, from nearby Colombia to Saudi Arabia, debate whether the time has come to transition the economy away from dependence on fossil fuels, in Mexico and Brazil, debates over energy policy continue to focus on nationalization versus privatization.

Considering resource nationalism’s poor track record in actually benefiting most citizens, it is time for these countries to shift the focus of policy discussions toward addressing today’s more pressing problems.

Lisa Viscidi is the director of the Energy, Climate Change, and Extractive Industries Program at the Inter-American Dialogue.

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Bolivia’s Oil Revenue To Reach $2.2 Billion

(Xinhua, 14.Oct.2018) — Bolivia’s oil revenue this year is estimated to reach 2.2 billion U.S. dollars as it “will be able to fulfill” contracts with its southern American partners, Minister of Hydrocarbons and Energy Luis Alberto Sanchez said Saturday.

“The income to the country is guaranteed,” Sanchez said. “We should feel certain about the expected income from the export of gas because we will be able to fulfill the contracts with Argentina until 2026 and with Brazil for the remaining volume to be delivered and an extension of the contract until 2024.”

Bolivia is negotiating an increase in gas sales in western Brazil, the minister said, adding that it is negotiating with new markets that will generate greater benefits through direct sale of natural gas to several Brazilian states.

“This is good for us because it opens up the Brazilian market. The country has all the right conditions to take on these new contracts and at better prices,” he said.

Bolivia is working on the export of liquefied natural gas (LNG) by way of the Peruvian port of Ilo on the Pacific coast, the government confirmed Saturday.

The deal with Paraguay is under negotiation to supply gas to the Chaco region, a sparsely inhabited area, both at the household level and for the generation of electricity, according to Humberto Salinas, vice minister of Industrialization, Commercialization, Transportation and Hydrocarbon Storage.

“We will be exporting to Paraguay and we will end up opening new overseas markets with the liquified natural gas,” Salinas said.

Bolivia is a major exporter of LNG in South America, with 99 percent of the exports going to Paraguay and Peru, the vice minister said, adding that it hopes to add Uruguay, Argentina and Brazil to the list of export destinations.

Between 1985 and 2005, Bolivia earned 4.587 billion dollars in oil revenue, at an average of 225 million dollars a year. From 2006 to 2015, the total reached 31.573 billion dollars, with a yearly peak of 5.489 billion dollars in 2014.

Bolivia’s GDP growth declined from a peak since the 1970s of 6.8 percent in 2013 to an estimated 4.2 percent in 2017 due to a less favorable international environment and a temporary reduction in the external gas demand, according to the World Bank.

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Energy Analytics Institute (EAI): #LatAmNRG

Mexico Plans To Enforce Odebrecht Fines Via Seizure -Official

(Reuters, 12.Oct.2018) — Mexico plans to enforce fines imposed on Odebrecht over corruption allegations by confiscating some $30 million owed by state oil company Pemex to the Brazilian firm, a top official at the public administration ministry said.

Christian Ramirez, coordinator-general of the public administration ministry (SFP), told Reuters on Tuesday that he expected Mexico’s tax authority to seize the $30 million “in the coming months.”

Brazilian construction firm Odebrecht has spent the past few years at the center of one of the largest corruption scandals in Latin America, and has admitted paying bribes from Peru to Panama.

In Mexico, the SFP imposed fines worth some $56.8 million in total on two Odebrecht subsidiaries in April. Since the end of 2017, it has punished several Odebrecht businesses in Mexico, barring them from signing contracts with public bodies for up to four years.

Mexico’s government did not detail the reasons for the fines, but officials said they related to probes into suspected corruption between Odebrecht and Pemex.

Ramirez on Tuesday said the Brazilian firm had “practically left” Mexico and that tax officials who recently visited an Odebrecht subsidiary only found “two computers and a desk.”

Neither Odebrecht in Mexico nor in Brazil responded to requests for comment. In April, the company said it planned to fight the fines.

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Energy Analytics Institute (EAI): #LatAmNRG

Guyana May be the Next Big Beast in Global Oil

(The National, Robin Mills, 8.Oct.2018) — One of the few major new conventional oil provinces discovered this century could see the country emerge as the top per capita producer.

Who will be the world’s largest oil producing country per person in the 2020s?

Kuwait perhaps, with 3 million barrels per day and a population just over 4 million? Saudi Arabia or, looking further afield, Brunei or Norway? No, that honour will belong to the South American nation of Guyana, which could well be sharing output of 700,000 barrels per day among just 770,000 people.

Although adjacent to Venezuela, Guyana has been better known for sugarcane, and cricketers such as Clive Lloyd, Lance Gibbs and Shivnarine Chanderpaul, than oil. But after first striking oil at Liza in 2015, ExxonMobil and partners Hess and China National Offshore Oil Corporation have made seven major discoveries in deep offshore waters, with production due to start in 2020.

Other companies, including Spain’s Repsol and African-focused explorer Tullow, are also looking. And the trend may extend into the former Dutch colony of Suriname to the east. Beyond Suriname is the overseas French department of French Guiana, where Tullow found oil in 2011 although follow-up exploration has been disappointing.

Guyana is one of the few major new conventional oil provinces discovered this century, along with the Kurdistan region of Iraq (which has subsequently disappointed) and India’s Rajasthan in 2004, Brazil’s “pre-salt” and Uganda in 2006, Ghana in 2007 and perhaps Senegal in 2014. After just four years of exploration drilling, Guyana is already set to be the biggest of these after Brazil. Estimated production costs of $46 per barrel are well below current oil prices, and competitive with shale or other leading deep-water areas.

Unlike the US’ mostly very light shale oil, Guyana’s is a medium-light crude closer to major Middle East grades. Likely to be rich in diesel when refined, it helps fill a hole in the world’s crude diet.

Finding new conventional oil is important for the global industry. Companies such as Shell, Total and Eni have increasingly shifted to gas, which has proved much easier to discover in quantity, while BP and their American peers, ExxonMobil, Chevron and ConocoPhillips, have focused on US shale. Both the International Energy Agency and Opec warn of under-investment and a coming oil crunch, but the major oil reserves in Opec countries and Russia are mostly closed off to international firms by government policy, insecurity and sanctions.

If the discoveries are significant for the world, they will be transformational for Guyana. Gross oil revenues of some $13 billion annually by the mid-2020s, or about $17,000 per inhabitant, contrast to its 2016 GDP of just $3.4bn. Only some 14 per cent of this will come to the government for the first two to three years while costs are paid off, but this is still an enormous bonanza.

But, like other new oil states, Guyana has to manage the perils of a sudden influx of wealth. It has good advice, as a member of the New Producers Group, an initiative of UK think tank Chatham House, the Natural Resource Governance Institute, and the Commonwealth, which brings together experts, politicians, government and civil society from a number of newly-established oil- and gas-producing countries.

These problems are well known but not so easy to solve. Government faces the risks of corruption, nepotism and patronage; a weakening of democracy; over-spending and vulnerability to falls in oil prices; and a lack of capability to manage oil operations and tax collection. The economy is threatened by conflicts over fiscal terms with the oil companies; the temptation to introduce wasteful energy subsidies; inflation and currency over-appreciation; and a loss of competitiveness from the non-oil sector. And the local population confronts unrealistic expectations of sudden wealth; an influx of outsiders; and environmental damage.

These issues are particularly salient for Guyana, a relatively small and poor country with quite high levels of corruption. It also neighbours troubled Venezuela, which has claimed two-thirds of its territory. Some Guyanese worry that the valuable work of oil services and contracting, a way to develop the domestic economy and skills, will be mostly supplied by next-door Trinidad and Tobago, which has a long-standing petroleum industry. The large gas resources found along with the oil also have to be used responsibly.

Much has been learned about potential solutions over the past two decades, though they come with their own conundrums. A sovereign wealth fund, like the Abu Dhabi Investment Authority or Norway’s oil fund, avoids a too-sudden influx of money; stabilises the government budget against oil price volatility; and saves for future generations. A robust political process and rules are needed to ensure the fund is not raided or diverted for pet projects.

A national oil company (NOC) helps build skills and strengthen the management of the sector. But it should not become a vehicle for handing out jobs to cronies or politicised meddling in the industry. Experienced lawyers, accountants, geologists and others are needed to staff a NOC and a petroleum regulator, and cannot be spread too thinly.

It is essential to educate the government machinery, media and civil society, so they understand how much money is coming in, and have a voice in how it is used. Bodies such as the Extractive Industries Transparency Initiative (EITI) report on oil revenues and their allocation.

Guyanese are fortunate to have contrasting examples next door in Venezuela of how a mismanaged oil sector can ruin a country; and Trinidad, where petroleum has generally been positive for the country.

International help and goodwill will hopefully ensure their oil is a bonus not just for the world economy but for the people.

Robin M. Mills is CEO of Qamar Energy, and author of The Myth of the Oil Crisis

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Venezuela Faces Fresh Blow With Ship-Fuel Rules Threatening Exports

(Bloomberg, 27.Sep.2018) — New rules forcing ships to use cleaner marine fuels may deal yet another blow to cash-strapped Petroleos de Venezuela SA, an exporter of high-sulfur fuel oil.

From Jan. 1, 2020, vessels will have to switch to less-polluting bunker fuel or be fitted with equipment to curb emissions, under new International Maritime Organization rules. That’s expected to weaken demand for the high-sulfur residual fuel oil produced by PDVSA, pushing prices lower at the same time that the cost of importing clean fuels rises, said Mel Larson, a consultant at KBC Advanced Technologies Inc.

As refiners prepare to produce IMO-compliant fuels that rely on low-sulfur crude oils, sour crude produced by Venezuela and Mexico may be sold at deeper discounts. Meanwhile, demand for lighter distillates, including diesel, is expected to increase. That ultimately will take a toll on the economies of Venezuela, Mexico and Ecuador that rely on imported diesel and gasoline.

“IMO 2020 has the potential to hurt GDP growth in most Latin American economies, especially the ones that subsidize fuel prices,” Larson said by email. “As the cost of imported fuels rise, subsidizing gasoline and diesel will only serve to expand a country’s or company’s debt load.”

Most refiners in Latin America haven’t invested in units that can remove sulfur or crack residuals into more valuable molecules. That puts them at a disadvantage ahead of the rule, which is expected to slash global demand for high-sulfur bunker fuel to as low as 1 million barrels daily from 4 million barrels currently.

By this measure, Petroleos Mexicanos and PDVSA, respectively Latin America’s largest and second-largest exporters of fuel oil, are the ones who have most to lose.

Petroleo Brasileiro SA, on the other hand, is set to take advantage of the fuel shift, according to Guilherme Franca, executive manager of commercialization. Petrobras already exports IMO-compliant fuels and is exploring the re-opening of fuel oil storage tanks in Singapore to better supply bunker fuel markets in Asia.

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Ecopetrol: Fracking Likely In Colombia, Business Prospects Are Positive

(Seeking Alpha, Dylan Quintilone, 14.Sep.2018) — Ecopetrol SA is a Colombian oil and gas company with headquarters in Bogotá, Colombia. The company is listed by Forbes as the 300th largest enterprise by profits and is the second oil company in South America behind Petrobras from Brazil.

Ecopetrol’s operations are divided between exploration and production; Refining, Petrochemical & Biofuels, Oil Transportation and Logistics. The company has around 8,500 kilometers of transportation pipelines which commercializes crude oil and all kinds of derivatives such as fuel oil, aviation gasoline, cracked naphtha, virgin naphtha, polypropylene resin, and masterbatches. The company offers refined and petrochemical products to multiple markets and has a large presence in Colombia.

The company has almost ten thousand employees and is experiencing a rising period of revenues due to the increase in oil prices in the first half of 2018. Ecopetrol has increased production in recent years and the company produces roughly 730 million barrels per year, which is an 83% production increase over 2010 levels. The company expects to surpass the billion barrel mark within the coming years because of additional discovery of oil reserves of the northern coast of Colombia and new exploration/extraction methods.

Fracking in Colombia? Most likely

Fracking in Colombia has been a big debate since the recently inaugurated president Ivan Duque was proposing the possibility during his election campaign. Upon securing the presidency, his fracking project is moving forward with a majority of the senators in the Colombian Congress who are collaborating with him for the proposal. The fracking issue has long been debated and now with the government reaching a consensus and backing the fracking industry, the approval for the controversial extraction method is likely.

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GeoPark Announces New Jauke Gas Field Discovery in Chile

(GeoPark, 20.Aug.2018) — GeoPark Limited announced the successful drilling and testing of the Jauke 1 exploration well in the Fell block (GeoPark operated, 100% WI) in Chile.

“This discovery illustrates the hydrocarbon-generating capacity of GeoPark’s unique Latin American multi-country platform,” said GeoPark Chief Executive Officer James F. Park.

GeoPark drilled and completed the Jauke 1 exploration well to a total depth of 9,592 feet. A production test through different chokes in the Springhill formation resulted in an average production rate of 5.8 mil lion standard cubic feet per day of gas (or 970 boepd) with a wellhead pressure of 2,738 pounds per square inch.

Additional production history is required to determine stabilized flow rates of the well and the extent of the reservoir. Surface facilities are in place, the well is in production, and the gas is being sold to Methanex through a long term gas contract. Drilling and completion costs are estimated at $3.4 million, and at current gas prices and testing rates, this well is expected to have a payback period of 6-7 months.

The Jauke gas field is part of the large Dicky geological structure in the Fell block – and has the potential for multiple development drilling opportunities. Petrophysical analysis also indicates hydrocarbon potential in the shallower El Salto formation which will be tested i n the future. The Jauke exploration effort is part of GeoPark’s 2018 overall 40-45 well drilling program in Colombia, Argentina, Brazil, and Chile – with five drilling rigs currently in operation.

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Ecopetrol Names New Corporate VP of Finance

Jaime Caballero Uribe. Source: Ecopetrol

(Ecopetrol, 8.Aug.2018) – Ecopetrol S.A. announced appointment of Jaime Caballero Uribe as the new Corporate Vice President of Finance (Chief Financial Officer).

The appointment is effective as of August 7, 2018.

Mr. Caballero has more than 20 years of experience with companies in the oil and gas sector, both in Colombia and abroad. He has served as Ecopetrol’s CFO for the Downstream Segment since July 2017. During this period he has also represented Ecopetrol at the Board of Directors of Propilco and Gases del Caribe, among other companies.

His experience prior to Ecopetrol includes 17 years at BP plc, where he held leadership positions in Colombia, North America, Africa and Europe, most recently as CFO for the Brazil region (encompassing Brazil, Uruguay, Colombia and Venezuela).

Mr. Caballero is an attorney with a degree from the Universidad de los Andes (Colombia). He has an MBA in Energy Business from the Fundação Getulio Vargas (Brazil), and has carried out executive studies in advanced financial management at Duke University and Wharton School of Business (University of Pennsylvania).

Mr. Caballero will be the compliance agent for financial reporting to the Colombian Finance Superintendency and the international markets.

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Trafigura Seeks to End Ricardo Eliçabe Conflict

(Energy Analytics Institute, Ian Silverman, 28.Jul.2018) – Negotiations continue to advance to overcome a labor related conflict at the Ricardo Eliçabe refinery in Bahía Blanca.

The refinery, acquired last May by the Dutch group Trafigura, has been paralyzed for almost two months, reported the daily newspaper Clarin.

The labor conflict stems from a decision by Trafigura in early June of 2018 to no longer acquire crude for processing. The decision affects an estimated 200 workers.

Recently, in a move to prevent layoffs, the union of Petroleum, Gas and Biofuels Workers has started to accept offers related to voluntary departures and retirements.

“If we can confirm the list of workers who would leave the refinery and it’s accepted by the company, we would close the conflict,” reported the daily, citing union official Fabio Pierdominici.

***

EIA Beta Interactive Data Analysis

(Energy Analytics Institute, Ian Silverman, 26.Jul.2018) – Beta data from the EIA provide users with an interactive way to analyze multiple petroleum data.

According to the most recent beta crude oil reserve data provided by the US-based Energy Information Administration, two countries in the Latin American region make the list and rank among the top 15 countries worldwide in terms of these reserves. To no surprise, Venezuela tops the list and Brazil ranks 15th, according to the data.

In terms of natural gas reserves, again Venezuela tops the list among the top 15 countries worldwide, but this time the South American country ranks 8th, according to the data.

***

Venezuela Oil Exports to China Slump

(Reuters, 17.Jun.2018) – Reuters) – China’s imports of Venezuelan crude oil could sink to their lowest in nearly eight years in July as the OPEC producer struggles with shrinking output and mounting logistics issues, according to people familiar with the matter and shipping data.

State-controlled PetroChina expects June loadings from Venezuela, mainly the Merey grade, to be half the normal rates, according to two Beijing-based oil officials briefed on the matter. Venezuela’s state firm PDVSA has promised the lost volume would be topped up in July loadings for arrival in August-September, they said.

The plunge in supplies to Venezuela’s most important customer, creditor and political ally is the latest indicator of tough times for the cash-strapped country with the world’s largest oil reserves. Crude output fell to the lowest annual average in over three decades between January and April, while claims on assets by creditors have cut off PDVSA’s access to export terminals.

The slide cuts both ways. China’s growing thirst for oil amid still-sturdy economic growth is increasing its reliance on imports, while Venezuela’s trouble exporting as its infrastructure crumbles means it’s missing out on crude oil prices that have risen to their highest in years.

“One of the best things about Venezuelan oil was its stable volumes for all these years and competitive prices,” said one senior oil industry official with direct knowledge of the supply situation. “But now they seem in very bad shape, not having the money to upgrade port facilities, no money even to remove the high water content in crude oil.”

The officials spoke on condition of anonymity because they weren’t authorised to discuss the matter with media.

Only one supertanker, the “New Pearl” carrying 2 million barrels of Venezuelan crude, is set to arrive in China’s eastern province of Shandong in July, down from this year’s monthly peak of 11 million barrels in March, according to Thomson Reuters Eikon trade flows data.

That would be the lowest monthly import volume since late 2010, according to Chinese customs data C-IMP-VECN-MTH.

PetroChina said it does not comment on market speculation. PDVSA did not immediately respond to Reuters’ requests for comment.

‘BIGGEST CASUALTY’

Disruptions in Venezuelan crude supplies to China started in April, and from mid-May through early June PDVSA did not load any crude for PetroChina, said the senior oil official. The Chinese firm lifted an average of around 20 million tonnes a year – or 400,000 barrels a day – in 2016 and 2017 of Venezuelan crude oil under a government-to-government loan-for-oil programme.

“Venezuela remains the biggest and most visible casualty of the (oil) market share war,” analysts at RBC Capital Markets led by Helima Croft said in a note on Thursday.

“We see almost no prospect of a turnaround in the Venezuelan story this year, at least barring a change in government, and even if the country comes under new management, it will still take a considerable amount of time and international assistance to right the ship and restore production.”

PDVSA has halted operations at units that convert extra-heavy oil into exportable crude. Early this month it asked customers to transfer oil at sea to clear a backlog of tankers waiting to load at its ports.

The Venezuelan firm has notified PetroChina of the new ship-to-ship requirement and agreed also to bear the additional cost, according to another industry executive with knowledge of the matter.

‘CHANGE DIET’

One trader with an independent Chinese refiner said he was still receiving offers of Venezuelan oil for August delivery at stable prices compared with a month ago, but added that the supply outlook is murky. “There isn’t a lot of cheap heavy crude (available) so some Chinese refineries might have to change diet a bit,” he said.

Sengyick Tee, a Beijing-based consultant at SIA Energy, said Chinese independents have increased imports of other heavy crude grades such as Castilla from Colombia and fuel oil as replacement.

Venezuela was the eighth-largest crude supplier to China last year, with 435,400 barrels per day (bpd), behind Brazil, according to China customs data.

But it already dropped to the ninth position in the first quarter of this year with an average volume of 381,300 bpd as China ramped up imports from Iraq, Kuwait and Brazil.

Venezuelan crude exports to India have also dropped 20 percent in the first five months to 323,600 bpd, according to data from shipping and industry sources.

Reliance Industries Ltd and Nayara Energy, key Venezuelan crude buyers, have stepped up imports of similar-quality oil from Brazil, Mexico, Kuwait, Iran, Iraq, the United Arab Emirates and Chad for replacement, data showed.

***

North America’s Energy Future on Trial in Mexico

(Brookings, Carlos Pascual, David G. Victor, and Rafael Fernandez de Castro, 5.Jun.2018) – On July 1, Mexicans head to the polls to select their next president. While it has become fashionable to wall Mexican matters away from American politics, in reality the Mexican election could transform the North American community. At the epicenter of that future is a quiet, steady effort to reform Mexico’s energy markets and roll back the monopolies of Mexico’s state-owned energy companies. These reforms have already triggered contracts that could yield $200 billion in investments in the coming years.

Editor’s Note:

The Mexican election could transform the North American community, write Carlos Pascual, David G. Victor and Rafael Fernandez de Castro Medina. At the epicenter of that future is a quiet, steady effort to reform Mexico’s energy markets and roll back the monopolies of Mexico’s state-owned energy companies. This piece originally appeared in the Houston Chronicle.

Until now, nobody has really known what Mexican voters think about all this change, but the answers matter because the contending candidates for the presidency have outlined starkly different visions for the future. In April, we ran—in tandem with the Brookings Institution, the University of California at San Diego, the global consultancy IHS Markit and a leading Mexican newspaper, El Financiero—the the first systematic poll of Mexican voter attitudes. What we found is disturbing and important as North Americans watch the upcoming elections.

On the surface, the picture is positive. Most strikingly, a modest majority of the public supports continuing the energy reforms (48 percent, versus 37 percent opposed) even if they feel they are not producing good results (61 percent versus 27 percent), or that they were not necessary (47 percent versus 41 percent). Mexicans feel that returning to the past isn’t a solution. For decades, Mexicans saw Pemex, whose nationalization in 1938 is still a national holiday, as the country’s crown jewel. Those days are gone. In our poll, Mexicans opined that Pemex has not acted to the benefit of the country (61 percent versus 30 percent). Mexico is at a crossroads—none of the old models works, but none of the new models are yet formed.

Digging deeper into the polling reveals disturbing insights. Mexicans, like Americans, actually know very little about the problems and opportunities in the energy sector. Sixty-three percent believed that Mexico’s oil production either increased or stayed the same in the 10 years prior to the constitutional changes in 2013. In reality, Mexico’s oil production peaked in 2004 at 3.5 million barrels per day, and by 2013 a persisting lack of investment had driven production down to 2.4 million barrels per day. It is not surprising that Mexicans are confused about the solutions—most don’t realize that production had collapsed.

Almost everything that is important in the energy sector takes a long time to bear fruit—that’s because investment cycles are long, and longer still when investors aren’t sure whether new policies will hold. It takes 3 to 5 years for investment to translate into production and, optimistically, two years before that to pass the laws and regulations needed to execute a bid round. Thus, when Mexico changed its constitution in 2013 to open oil production to outside investors, it was going to take at least 5 to 7 years before oil production might increase. By that standard, the reforms are exactly on schedule: Today, more than 100 fields have been awarded for investment, there have been significant initial commercial finds and production is set to rise around 2020. No country in the world has managed such a complete transformation of its energy sector faster than Mexico.

For the public, reforms may still seem like unfulfilled promises. North of the border, these results really matter because it is American companies—with American jobs and investors—that are perhaps best poised to benefit from Mexico’s continued opening.

As much as Mexico has evolved as a competitive global economy, accumulating an impressive number of free trade agreements that open the country to international commerce and investment, the public fears that private investment in oil would not benefit the Mexican people (51 percent versus 34 percent). Mexicans are also suspicious of depending on foreigners. Almost two-thirds of the respondents believed that it is a significant risk for Mexico to import more than 50 percent of its gasoline and natural gas from the United States. That’s bad news for Americans who have become the number one exporter of natural gas and refined oil products like gasoline.

Just as Mexicans are becoming impatient to see tangible benefits from reform, many other oil producers are in intense competition to attract private investors—from Saudi Arabia to Russia and Brazil. Traditionally, big oil producers could afford to be inefficient because the money kept sloshing in. Those days are gone, and the whole world’s oil industry is in an arms race to reform and get better.

For the last two years, the United States has been making loud noises about cutting off Mexico. Now it is Mexico’s turn, and the big losers could be American companies that want to do business south of the border. Fixing this problem won’t be easy, but it starts with talking openly—with the public, not just elites—about how reform actually works. And why openness and competition are good news all around.

***

Mexico’s Vista Oil & Gas Signs Onshore JV With Jaguar

(Reuters, 23.May.2018) – Mexican energy investment firm Vista Oil & Gas will tie up with Jaguar Exploracion y Produccion on three onshore projects, the company said on Tuesday, acquiring 50 percent stakes with an initial payment of nearly $27.5 million.

Vista will pay Monterrey-based Jaguar a further $10 million to compensate the firm for past investments in the projects, or so-called carry costs, the firm said in a statement.

The three onshore projects were won at auctions last July by Jaguar, an upstart oil firm owned by Mexico’s Grupo Topaz, and are located in the Gulf coast states of Tabasco and Veracruz.

Two of the blocks will be operated by Vista, while the other will be run by Jaguar, in what Vista described as Mexico’s first joint venture between two private oil firms.

The joint venture between the two must still be approved by the National Hydrocarbons Commission, the Mexican oil regulator that supervises exploration and production contracts.

Last year, Vista became Mexico’s first publicly traded oil firm, four years after a landmark energy reform ended the decades-long monopoly enjoyed by state-owned Pemex.

Vista, which has targeted assets for possible acquisition in Mexico, Brazil, Colombia and Argentina, is backed by private equity firm Riverstone Capital.

***

Bolivia, Denmark Invest $193.9 Mln in Santa Cruz Projects

(Energy Analytics Institute, Ian Silverman, 30.Apr.2018) – Bolivia and Denmark plan to invest $193.9 million on wind complexes in Warnes, San Julián and El Dorado in Bolivia’s Santa Cruz department. Bolivia and Denmark will front $66.8 million and $24 million, respectively, of the total investment. The difference or $103.1 million will be come via a credit, reported the daily La Razón, without providing details. In total, the three complexes will generate 108 megawatts of energy, according to the daily.

The projects comprise a greater initiative by the Bolivian government to generate sufficient energy to cover demand in the domestic market, and also export surplus energy to neighbors such as Argentina and Brazil.
***

Mexico’s Gasoline Price Lowest in LAC Region

(Energy Analytics Institute, Fidencio Casillas, 16.Jan.2017) – The average gasoline price in Mexico, the largest Spanish speaking country in the Americas, is still the lowest amongst select countries in the Latin American and Caribbean (LAC) region.

Mexico’s average gasoline price of 15.9 Mexican pesos per liter remains the lowest among select countries in the LAC region, according to data published by state oil company Petróleos Mexicanos S.A. de C.V. (Pemex). Uruguay, with an average gasoline price of 29.3 Mexican pesos per liter, is the Southern Cone country in the LAC region with the highest average gasoline price, followed thereafter by Cuba in the Caribbean and then Belize in Central America.

Country ——————— Gasoline Price in Mexican Pesos per Liter

Uruguay ——————– 29.3

Cuba ———————— 27.3

Belize ———————- 24.4

Brazil ———————– 23.7

Dominican Republic —- 23.3

Chile ———————– 23.1

Argentina —————– 23.1

Costa Rica —————- 20.2

Peru ———————— 20.2

Paraguay —————— 20.0

Honduras —————— 19.6

Nicaragua —————– 19.0

Mexico ——————– 15.9

Source: Pemex

Gasoline prices in Mexico increased — effective as of January 1, 2017 — as part of a plan by the government to boost fuel prices in line with international oil prices, said Mexican President Enrique Pena Nieto in a speech broadcast on Mexico’s Televisa television station.

***

YPFB to Sign Contracts with YPF and Petrobras

(Energy Analytics Institute, Jared Yamin, 7.Jun.2016) – YPFB plans to sign exploration contracts with its Argentine and Brazilian counterparts in July.

YPFB will sign exploration agreements with its Argentine counterpart YPF for the Charagua, Abapó and Yuchan areas and agreements with its Brazilian counterpart Petrobras for the San Telmo and Astillero áreas, reported the daily newspaper La Razón, citing YPFB President Guillermo Achá.

The San Telmo and Astilleros areas cover an extension of close to 210 hectares, reported the daily.

***

Petrobras Pays Fine in USA

(Petrobras, 20.Aug.2015) – Regarding media reports on the payment of a fine to U.S. authorities, Petrobras states there is nothing ongoing regarding any payment of a fine to close civil and criminal investigations into the violation of anticorruption legislation in the U.S.

Nor has there been any decision by U.S. authorities on the merits of such an investigation or the amounts involved.

***

Petrobras Updates on NY Lawsuit

(Petrobras, 25.Jun.2015) – Petrobras announced that on 25.Jun.2015, a hearing was held before the federal court in New York regarding the motion to dismiss presented by Petrobras in the class action lawsuit in which the company is a defendant. The purpose of the motion to dismiss is for the federal court to determine if, from a legal point of view, the allegations are sufficient to proceed to the evidentiary stage of the case (discovery).

After hearing the oral arguments, the judge informed that he will enter his decision on the motion to dismiss in due course.

***

Gran Tierra Announces Full 1Q:15 Results

(Gran Tierra Energy Inc., 6.May.2015) – Gran Tierra Energy Inc. announced its financial and operating results for the quarter ended 31.Mar.2015. All dollar amounts are in U.S.A. dollars unless otherwise indicated.

Earlier this year, Gran Tierra announced significant changes to the company’s leadership, strategic direction and cost structure. Gran Tierra’s operations and resources are now focused on Colombia, where, as its first quarter production demonstrates, the company has a record of success and strong performance. Gran Tierra continues to maintain a solid financial position with cash balances reflecting expenditures that were pre-committed prior to this strategic shift. With these legacy commitments largely behind Gran Tierra and the cost reductions announced earlier this year, the company has significantly improved its capital efficiency and continues to review opportunities for additional cost savings. Gran Tierra is confident that the actions it has taken better position the company for growth and value creation despite what continues to be a challenging lower oil price environment.

Financial and Operating Highlights:

— Due to strong Colombian performance, oil and natural gas production for the quarter was above company projections. Production averaged 24,015 boe/d gross working interest (WI), or 20,140 boe/d net after royalties (“NAR”) before adjustment for inventory changes and losses, or 19,399 boe/d NAR adjusted for inventory changes and losses, compared with 25,245 boe/d gross WI and 19,029 boe/d NAR before adjustment for inventory changes and losses and 18,753 boe/d NAR adjusted for inventory changes and losses in the corresponding period in 2014. Approximately 99% of this production was oil with the balance consisting of natural gas.

— The company is making progress on the Chaza Block in Colombia. The Moqueta-17 development well was successfully completed, stimulated and tiedin as an oil producer. The Moqueta-18i injection well was drilled and encountered mechanical difficulties. This well was being drilled to provide pressure support to the Moqueta field south block. It is currently suspended pending the results of injectivity testing at Zapotero-1, which is located in the same fault compartment as Moqueta 18i. Initial injectivity is proving to be successful with 2,500 b/d of water being injected, and the company expects to increase this to 5,000 b/d of water.

— Gran Tierra expects to achieve reductions of approximately 30% in general and administrative (“G&A”) expenses in 2015 compared with 2014. These expected savings are due to the previously announced 20% reduction in headcount, other cost cutting initiatives in all locations, and strengthening of the U.S. dollar against local currencies in South America, and exclude one-time severance expenses of $4.4 million. On a barrel of oil equivalent (BOE) basis, G&A expenses decreased by 41%, or $2.85/BOE in the 1Q:15 from the 4Q:14. Further optimization of G&A expenses is expected.

— Cost optimization initiatives resulted in $1.1 million of operating expense reductions in Colombia during the quarter and an 11% negotiated reduction in Colombian trucking tariffs. Operating expenses decreased by 13% to $18/boe in the 1Q:15 from $20.75/boe in the 4Q:14. The company expects to achieve up to $5 million of additional operating cost savings in Colombia in 2015, primarily as a result of its use of produced gas for power generation and renegotiated supply and service contracts.

— Due to lower oil prices, revenue and other income for the quarter was $76.7 million in the 1Q:15, a 23% decrease from $99.6 million in the 4Q:14, and a 50% decrease from $151.9 million in the comparable period in 2014.

— Net loss for the 1Q:15 was $44.9 million, or $0.16 per share basic and diluted, compared with a net loss of $269.8 million, or $0.94/share basic and diluted, in the 4Q:14, and net income of $45.1 million, or $0.16/share basic and diluted, in the 4Q:14.

Results in both this quarter and the 4Q:14 were significantly impacted by the company’s decision to cease development of the Bretaña field on Block 95 in Peru other than making those expenditures necessary to maintain tangible asset integrity and security, which resulted in impairment losses of $32.7 million and $265.1 million, respectively, in Gran Tierra’s Peru cost center. Included in the Peru cost center impairment loss of $32.7 million, was $14.0 million of drilling costs for the Bretaña Sur 953-4-1X appraisal well, $6.2 million for the construction of the long-term test facilities, $5.0 million relating to contract termination fees associated with the decision not to proceed with the long-term test, and $7.5 million of other costs including restocking fees and the front end engineering design (“FEED”) study. Total contract termination and restocking fees were $8.7 million.

— Funds flow from continuing operations for the 1Q:15 were consistent with company projections at $25.6 million, a decrease of 49% from $50.3 million in the 4Q:14, and a decrease of 71% from $86.7 million in the 1Q:14.

— The company maintains strong balance sheet with cash and cash equivalents of $203.5 million at March 31, 2015.The company’s cash balance reflects $74 million of capital expenditures in the first quarter of 2015 that were incurred largely as a result of precommitted costs associated with legacy projects and decisions made before the senior management and strategy changes. Reflecting Gran Tierra’s new strategic direction and focus on Colombia, in February 2015, Gran Tierra announced a $170 million reduction to its capital budget, and continues to expect 2015 capital expenditures of $140 million.

— In Brazil, Tiê field operations were suspended on March 11, 2015, following a regional facilities audit by the Agência Nacional de Petróleo Gás Natural e Biocombustíveis (ANP). Gran Tierra expects resumption of operations by May 20, 2015.

First Quarter 2015 Financial Highlights

For the three months ended 31.Mar.2015, revenue and other income decreased by 50% to $76.7 million compared with $151.9 million in the corresponding period in 2014 primarily due to decreased realized prices. Average realized oil prices decreased by 51% to $43.79/bbl for the 1Q:15, from $89.89/bbl in the 1Q:14 primarily as a result of lower benchmark prices. In the 1Q:15, an oil inventory and losses increase primarily in Colombia accounted for reduced production of 0.1 MMbbl or 741 bo/d.

Additionally, beginning July 1, 2014, the port operations fee component of the Ecopetrol S.A. operated Trans-Andean oil pipeline (the “OTA pipeline”) structure increased by $2.94/bbl, resulting in a reduction of realized oil prices by this amount on sales delivered through the OTA pipeline.

Revenue and other income for the 1Q:15, decreased by 23% to $76.7 million from $99.6 million compared with the 4Q:14 primarily due to decreased realized prices. Average realized oil prices decreased by 30% to $43.79/bbl for the 1Q:15, compared with $62.91/bbl in the 4Q:14, due to lower benchmark prices.

The average Brent oil price for the 1Q:15, was $53.91/bbl compared with $108.17/bbl in the 1Q:14, and $76.40/bbl for the 4Q:14. The average West Texas Intermediate oil price for the 1Q:15, was $48.63/bbl compared with $98.68/bbl in the 1Q:14, and $73.15/bbl for the 4Q:14.

During periods of OTA pipeline disruptions Gran Tierra uses transportation alternatives. These sales have varying effects on realized prices and transportation costs. During the three months ended March 31, 2015, 80% of Gran Tierra’s oil volumes sold in Colombia were through the OTA pipeline and only 20% were through these transportation alternatives. During the corresponding period in 2014, sales through the OTA pipeline were 41% of Gran Tierra’s oil volumes sold in Colombia and 59% were through transportation alternatives. The effect on the Colombian realized price for the 1Q:15, was an increase of approximately $0.01/boe, as compared with delivering all of Gran Tierra’s Colombian oil through the OTA pipeline, compared with a reduction of approximately $8.63/boe in the 1Q:14. Production during the 1Q:15, reflected approximately 10 days of oil delivery restrictions in Colombia compared with 51 days of oil delivery restrictions in the 1Q:14.

Operating expenses increased by 44% to $31.4 million for the 1Q:15, compared with $21.9 million in the 1Q:14. For the 1Q:15, the increase in operating expenses was primarily due to an increase in the operating cost per BOE. Operating expenses increased by 39% to $18/boe in the 1Q:15, from $12.96/boe in the 1Q:14, primarily as a result of higher transportation costs associated with higher sales using the OTA pipeline, which carried higher transportation costs instead of the realized price reductions that are incurred with some alternative customers, and increased workover expenses.

Operating expenses decreased by 4%, or $1.4 million, in the 1Q:15, from $32.8 million in the 4Q:14 primarily due to reduced operating costs per BOE. On a per BOE basis, operating expenses decreased by 13% to $18/boe for the 1Q:15, from $20.75/boe in the 4Q:14 as a result of cost reduction initiatives, deferral of road and equipment maintenance and higher production adjusted for inventory changes and losses.

DD&A expenses for the 1Q:15, increased to $86.2 million from $44.3 million in the 1Q:14. DD&A expenses in the 1Q:15, included $32.7 million of impairment charges in Gran Tierra’s Peru cost center relating to costs incurred in the 1Q:15 on Block 95 and a $4.3 million ceiling test impairment loss in Gran Tierra’s Brazil cost center relating to lower oil prices. Included in the Peru cost center impairment loss of $32.7 million, was $14.0 million of drilling costs for the Bretaña Sur 95-3-4-1X appraisal well, $6.2 million for the construction of the long-term test facilities, $5.0 million relating to contract termination fees associated with the decision not to proceed with the long-term test, and $7.5 million of other costs including restocking fees and the FEED study. Total contract termination and restocking fees were $8.7 million. The depletion rate increased by 88% to $49.35/boe from $26.23/boe primarily due to the 2015 impairment charges. If Brent oil prices continue at current levels, Gran Tierra believes it is reasonably likely that it would record further ceiling test impairment losses in its Brazil cost center in 2015 and, possibly, in its Colombia cost center. Additionally, Gran Tierra expects to record further impairment losses in its Peru cost center for costs incurred on Block 95 in 2015.

G&A expenses for the 1Q:15, decreased by 43% to $7.3 million ($4.18/boe) from $12.9 million ($7.62/boe) in the 1Q:14. The decrease was mainly due to the effect of the strengthening of the U.S. dollar against the Colombian peso which resulted in significant savings for costs denominated in local currency and a 20% reduction in the number of Gran Tierra’s full-time employees in March 2015 as part of the company’s cost saving measures and focus on reductions to other G&A expenses. Further optimization of G&A expenses is expected. G&A expenses in the three months ended 31.Mar.2015, are also net of a credit of $1.7 million ($0.97/boe) relating to the reversal of stock-based compensation expense for unvested options and restricted stock units on employee terminations.

Severance expenses for the 1Q:15, were $4.4 million compared with $nil in the 1Q:14. In March 2015, Gran Tierra reduced the number of its full-time employees by 20%.

Equity tax expense for the 1Q:15, of $3.8 million, represented a Colombian tax which was calculated based on Gran Tierra’s Colombian legal entities’ balance sheet equity for tax purposes at 1.Jan.2015. The legal obligation for each year’s equity tax liability arises on 1.Jan. of each year, therefore, Gran Tierra recognized the 2015 annual amount of the equity tax payable on its consolidated balance sheet at 31.Mar.2015, and a corresponding expense in its consolidated statement of operations during the 1Q:15.

Foreign exchange gain for the 1Q:15, was $11.5 million comprising an unrealized non-cash foreign exchange gain of $9.0 million and realized foreign exchange gains of $2.5 million. For the 1Q:14, there was a foreign exchange gain of $4.2 million, which was primarily a $4.2 million unrealized non-cash foreign exchange gain. Unrealized foreign exchange gains were primarily the result of the impact of the weakening of the Colombian peso versus the U.S. dollar on a net monetary liability position in Colombia.

For the 1Q:15, financial instruments gains included $2.4 million of unrealized financial instruments gains which were offset by $2.4 million of realized financial instrument losses. Financial instrument gains and losses related to unrealized gains on the Madalena Energy Inc. shares Gran Tierra received in connection with the sale of its Argentina business unit and gains and losses on Gran Tierra’s Colombia peso nondeliverable forward contracts.

Income tax expense related to continuing operations was $0.1 million for the 1Q:15, compared with $29.7 million in the 1Q:14. The decrease was primarily due to lower taxable income.

Loss from continuing operations was $44.9 million, or $0.16/share basic and diluted, for the 1Q:15, compared with income from continuing operations of $49.8 million, or $0.18/share basic and diluted, in the 1Q:14. As noted above, in the 1Q:15, Gran Tierra recorded impairment losses of $32.7 million in its Peru cost center relating to costs incurred on Block 95 and $4.3 million in its Brazil cost center due to lower oil prices.

Additionally, loss from continuing operations was impacted by decreased oil and natural gas sales as a result of lower realized oil prices, higher operating, DD&A, severance and equity tax expenses and lower financial instrument gains which were partially offset by lower G&A expenses, increased foreign exchange gains and lower income tax expenses.

Loss from discontinued operations, net of income taxes, was $nil for the 1Q:15, compared with $4.6 million, or $0.02/share basic and diluted, in the 1Q:14. Gran Tierra sold its Argentina business unit on 25.Jun.2014.

Net loss for the 1Q:15, was $44.9 million, or $0.16/share basic and diluted, compared with net income of $45.1 million, or $0.16/share basic and diluted, in the 1Q:14 and net loss of $269.8 million, or $0.94/share basic and diluted, in the 4Q:14.

Balance Sheet Highlights

The company’s repositioning strategy will help ensure that Gran Tierra maintains a strong balance sheet. Cash and cash equivalents were $203.5 million at 31.Mar.2015, compared with $331.8 million at 31.Dec.2014. The decrease was primarily due to capital expenditures incurred during the quarter of $74.0 million ($21.4 million in Colombia, $38.0 million in Peru, $13.9 million in Brazil and $0.7 million in Corporate) associated with the decisions by the prior management team and the costs associated with those legacy projects, $53.8 million of net cash outflows related to property, plant and equipment ($45.1 million outflow in Colombia, $9.4 million outflow in Peru, and a $0.7 million inflow in Brazil and Corporate), $26.1 million of net cash outflows related to assets and liabilities from operating activities and a $0.5 million increase in restricted cash, partially offset by funds flow from continuing operations of $25.6 million and proceeds from the issuance of shares of common stock of $0.5 million. Changes in assets and liabilities associated with operating and investing activities from 31.Dec.2014 to 31.Mar.2015, resulted in cash outflows of $83.1 million due to the payment of accounts payable and accrued liabilities partially offset by cash inflows of $3.2 million related to other assets and liabilities in the quarter.

Working capital (including cash and cash equivalents) was $181.3 million at 31.Mar.2015, a $58.6 million decrease from 31.Dec.2014. Gran Tierra remains debt free.

Production Highlights

Production for the 1Q:15 averaged 24,015 boe/d WI, or 20,140 boe/d NAR before adjustment for inventory changes and losses, or 19,399 boe/d NAR adjusted for inventory changes and losses, compared with 25,245 boe/d gross WI and 19,029 boe/d NAR before adjustment for inventory changes and losses and 18,753 boe/d NAR adjusted for inventory changes and losses in the corresponding period in 2014. Production for the 1Q:15 consisted of 18,748 boe/d NAR in Colombia and 651 bo/d NAR in Brazil, all adjusted for inventory changes and losses. Production in April 2015 averaged approximately 18,700 boe/d NAR before adjustment for inventory changes and losses, due to temporary operational shut-ins and approximately one day of oil delivery restrictions in Colombia. Gran Tierra expects production to be back to normal daily production levels after resumption of operations on the Tiê field in Brazil. Approximately 99% of this production is expected to be oil, with the balance consisting of natural gas.

During the 1Q:15, an oil inventory and losses increase accounted for 0.1 MMbbls, or 741 bo/d, of reduced production, compared with an oil inventory and losses increase which accounted for 24,784 barrels, or 276 bo/d, of reduced production in the 1Q:14.

Gran Tierra anticipates 2015 production to average between 21,800 boe/d and 22,300 boe/d gross WI, or 18,200 boe/d and 18,700 boe/d both NAR before adjustments for inventory changes and losses. This includes between 17,300 boe/d and 17,800 boe/d both NAR from Colombia and 900 bo/d NAR from Brazil. Approximately 99% of this production is oil, with the balance consisting of natural gas.

2015 Capital Program

In concert with Gran Tierra’s repositioning strategy, the planned 2015 capital program was reduced to $140 million from $310 million in early February 2015. This includes $60 million for Colombia, as well as funds that were pre-committed for non-core legacy projects, including $55 million for Peru, $24 million for Brazil and $1 million associated with corporate activities. The capital spending program allocates: $45 million for drilling; $49 million for facilities, pipelines and other; and $46 million for G&G expenditures. Approximately $35 million of the capital program is dedicated to the maintenance of existing production while $21 million is dedicated to drilling in Colombia.

During the 1Q:15, the company incurred $74.0 million of capital expenditures, which included $21.4 million in Colombia, $38.0 million in Peru, $13.9 million in Brazil and $0.7 million at Corporate. Capital expenditures in Peru included $32.7 million on Block 95 and $5.3 million on Gran Tierra’s other blocks.

On Block 95, all capital expenditures recorded had been completed or committed to prior to the advent of the repositioning strategy in Feb.2015 and included: $14 million of drilling costs for the Bretaña Sur 95-3-4-1X appraisal well; $6.2 million for the construction of the long-term test facilities; $8.7 million recorded unavoidable costs for contract termination fees associated with the decision not to proceed with the long-term test, and other contract termination and restocking fees; and $3.8 million related to the FEED study and other.

Gran Tierra is evaluating all contractual commitments on the company’s blocks with the objective of rationalizing this portfolio through farm outs, transfers and relinquishment. Gran Tierra expects the 2015 capital program to be funded through cash flows from operations and cash on hand at current production and oil price levels.

First Quarter 2015 Operational Highlights

COLOMBIA

Chaza Block, Putumayo Basin (Gran Tierra 100% WI and Operator)

In the 1Q:15, Gran Tierra successfully completed, stimulated and tied-in the Moqueta-17 development well in the Moqueta field as an oil producer. Moqueta-17 is now producing approximately 400 bo/d gross from the Villeta T and Caballos reservoirs. The Moqueta-18i injection well was drilled and encountered mechanical difficulties. It is currently suspended pending the results of injectivity testing at Zapotero-1, which is interpreted to be in the same fault compartment as Moqueta 18i (the Moqueta South Block). Initial injectivity tests on Zapotero-1 have been very positive and Gran Tierra is currently injecting approximately 2,500 b/d of water into the target Moqueta reservoir compartments, and expects to increase this to 5,000 b/d of water. The company expects that the water injection will create a positive pressure response in the Moqueta South Block updip oil bearing reservoirs and support oil production.

Gran Tierra continued facilities work at the Costayaco and Moqueta fields. In the first week of Mar.2015, the Company implemented a cogeneration project which utilizes produced gas and converts it to electricity to power the facilities at the Moqueta field.

Two 500 kilowatt power generators are generating 1 megawatt (MW) of power with the gas produced from the Moqueta field. This nearly meets the 1.2MW electrical needs of Moqueta. As a third party owns the generators and sells the electricity back to Gran Tierra at a lower rate than the national electrical utility, the project required no capital investment. This project is expected to provide both environmental and cost benefits by reducing the flaring of gas and cutting the cost of electricity to the field. Additionally, when excess electricity is generated, there is an opportunity to sell that excess to the national grid. This project is estimated to generate operating cost savings of approximately $350,000 in 2015. A similar co-generation project is currently being planned for the Costayaco field before year-end.

Gran Tierra has renegotiated contracts with its suppliers and service providers during the quarter and expects to achieve savings of up to $5 million from this initiative in 2015. Also during the quarter, Colombian trucking tariffs were renegotiated from a 5% reduction in early February to an 11% reduction by quarter-end. Gran Tierra also achieved $1.1 million of savings in the quarter mainly through staff and salary reductions, lower road maintenance due to decreased trucking transportation, and operational efficiencies related to reduced energy consumption.

Gran Tierra experienced higher than expected pipeline transportation during the quarter with approximately 85% of the Company’s Colombian crude being shipped through the OTA pipeline to the Port of Tumaco or through the Oleoducto de Crudos Pesado (“OCP”) pipeline to the Port of Esmeraldas, with the remainder transported by truck or other pipelines. Gran Tierra’s crude sold at the Ports of Tumaco and Esmeraldas received higher prices due to lower oil quality discounts than volumes trucked or shipped north to Barranquilla. Trucked volumes also have higher transportation costs which either decrease realized oil prices or increase operating costs.

Cauca-7 Block, Cauca Basin (Gran Tierra 100% WI and Operator)

The acquisition of 97km of 2-D seismic on the Cauca-7 Block, which commenced in the 4Q:14, was completed in the 1Q:15. Processing and interpretation is underway.

Sinu-3 Block, Sinu San Jacinto Basin (Gran Tierra 51% WI and Operator)     The acquisition of 487km of 2-D seismic on Sinu-3, which commenced in the 4Q:14, was completed in the 1Q:15. Processing and interpretation is ongoing. The company also commenced environmental impact assessments (“EIA”s) for future drilling on this block.     Putumayo-10 Block, Putumayo Basin (Gran Tierra 100% WI and Operator)

To fulfill the work commitment for the first exploration phase of this contract, Gran Tierra plans to acquire 73km of 2-D seismic on this block this year. During the 1Q:15, the company continued preparations for the seismic acquisition.

PERU

Block 95, Bretaña field, Marañon Basin (Gran Tierra 100% WI and Operator)

As announced in Feb.2015, the company ceased all further development expenditures on the Bretaña field on Block 95 other than what is necessary to maintain tangible asset integrity and security. Gran Tierra has since commenced dismantling, removal and abandonment of the Bretaña long-term test facilities.

BRAZIL

As announced in Feb.2015, the Company has refocused its strategy and resources on its core operations in Colombia. As a result of this change in strategy, in Brazil, the company will focus capital spending to facilities at the Tiê field. These facilities are expected to allow the company to maintain existing production levels.

Blocks 129, 142, 155, Recôncavo Basin (Gran Tierra 100% WI and Operator)

The First Appraisal Plan (“PAD”) phase will end 24.May.2015, before which Gran Tierra must decide whether to move to the next exploration phase. Gran Tierra has requested a suspension of the PAD phase and is awaiting a response from the ANP.

On 11.Mar.2015, the ANP suspended Tiê field operations due to region-wide facilities audits. Pursuant to this audit, Gran Tierra completed a risk analysis, prepared additional documentation and presented this to the ANP on 17.Mar.2015, and 10.Apr.2015. Gran Tierra expects operations will resume by 20.May.2015.

Gran Tierra initiated construction of an infield gas line connecting the 3-GTE-03-BA well to the Tiê Facilities. This tie-in is expected to be completed in the second quarter.

Importantly, the ANP has authorized the extension of Tiê field gas flaring through Jul.2015. The original gas flaring authorization was to expire Mar.2015.     Block 224, Recôncavo Basin (Gran Tierra 100% WI and Operator)     Gran Tierra received an extension to drill the Block 224 commitment well. The company now has one year following the approval of the pending EIA to drill the commitment well.     Blocks 86, 117, 118, Recôncavo Basin (Gran Tierra 100% WI and Operator)

Gran Tierra completed the acquisition of the 3-D seismic program that had been initiated in the 4Q:14. Processing of the 3-D seismic is ongoing.

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Moody’s Confirms Petrobras Argentina Notes

(Moody’s, 28.Apr.2015) – Moody’s Latin America Agente de Calificación de Riesgo confirmed the Ba2/Aaa.ar global scale rating and national scale rating on Petrobras Argentina S.A.’s (Petrobras Argentina) $300 million in guaranteed Series S notes (CUSIP 71646JAB5).

The rating action reflects Moody’s Investors Service’s rating action on 27.Apr.2015 of confirming Petrobras’ (Petrobras, the guarantor) global debt ratings at Ba2. The ratings outlook is now stable, also in accordance to Petrobras’ rating outlook. This concludes the ratings review period started in late-Dec.2014.

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Petrobras Reports Sale of Assets in Argentina

(Petrobras, 31.Mar.2015) – The Board of Directors of Petrobras Argentina (PESA) approved the sale of all of its assets in the Austral Basin (province of Santa Cruz) to Compañia General de Combustibles S.A. (CGC) for $101 million.

PESA assets involved in the deal include 26 onshore exploration and production concessions, with average oil and gas output of 15,000 boe/d, as well as all the distribution, treatment and storage infrastructure required.

This is the first sale of Petrobras assets under the 2015-2016 Divestment Plan released on 2.Mar.2015. The plan is expected to raise $13.7 billion.

The payment was made when the contract was signed, and this sale will therefore be accounted in the 1Q:15 results, with an estimated impact of $65 million in net income.

Completion of the deal is subject to the approval of the competent Argentine authorities.

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Argentina Seeks to Import 200MW from Bolivia

(Energy Analytics Institute, Ian Silverman, 24.Mar.2015) – Argentina is considering importing 200 megawatts of energy from Bolivia in 2015, announced Bolivia’s President Evo Morales.

The official also announced Brazil was also requesting more energy, without providing details, reported the daily newspaper La Razón.

“Perhaps this year we are going to start to export those 100 to 200 megawatts that Argentina is requesting,” said Morales during a visit to Cochabamba.

Bolivia has the capacity to export 100 megawatts of energy to Argentina and could slowly increase this capacity as projects come online, said Bolivia’s Hydrocarbon Minister Juan José Sosa Soruco on September 8, 2014.

“At this moment we cannot put our generation system at risk, so we can only consider 100 megawatts this year,” said Sosa. “By 2020 it is possible that we could be exporting 1,000 megawatts.”

Bolivia’s energy reserves are expected to increase this year from 300 megawatts to 500 megawatts with the Warnes thermo-electric plant in Santa Cruz department, according to a March 2, 2015 report from National Electricity Company (ENDE Corporación) President Eduardo Paz.

At the moment maximum electricity demand is 1,298 megawatts while the installed generating capacity on the National Interconnected System (SIN) or electricity grid is 1,600 megawatts, which leaves about 300 megawatts available, according to Paz.

“Our available resources for export are 300 megawatts now but with the addition of the Warnes plant his figure will increase to 500 megawatts,” said Paz. With the addition of the 200 megawatts from the Warnes project, Bolivia will be able to increase the capacity on the SIN to 1,800 megawatts.

During Morales’ nine year tenure as president, the capacity on the SIN has increased to 1,200 megawatts from 700 to 800 megawatts when he first entered office, the official said from Cochabamba.

Bolivia is working on the Yacuiba-Tartagal (Bolivia-Argentina) transmission line whereby it will be able to export excess energy to Argentina, said Morales.

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Petrobras Reports on Appointment of Plaintiff

(Petrobras, 6.Mar.2015) – Petrobras announces that on March 4, 2015, the presiding judge appointed Universities Superannuation Scheme, Ltd. as the lead plaintiff in the Class Action filed against Petrobras in the New York federal court.

A conference call between the presiding judge, Petrobras and the lead plaintiff will take place on March 6, 2015, in order to plan the next steps in the proceeding.

As the company stated on February 13th, 2015, it has hired a specialized U.S. law firm and will defend itself against the allegations in this lawsuit.

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Perenco to Buy Petrobras Assets in Colombia

(Energy Analytics Institute, Ian Silverman, 29.Oct.2013) – Petrobras plans to sell its interest in onshore blocks and two pipelines to France’s Perenco for $380 million to focus more attention on projects in Brazil, reported the daily newspaper El Espectador

The deal includes interest in: 11 onshore blocks that are producing an average 6,530 boe/d, the Petrobras Colombia and Alto Magdalena pipelines which have capacity to transport 14,950 b/d and 9,180 b/d, respectively.

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PDVSA Incorporates New Tankers into Fleet

(Energy Analytics Institute, Ian Silverman, 25.Oct.2013) – PDVSA President Rafael Ramirez speaks to reporters in Puerto la Cruz, Venezuela about introduction of news tankers into fleet.

Highlights of the discussion follow:

PDVSA incorporates VLCC Ayacucho and Suezmax Rio Arauca tankers, both built in China, into its fleet.

The new PDVSA VLCC Ayacucho tanker (332 meters long x 60 meters wide) has oil capacity to transport 2 MMbbls.

The PDVSA VLCC Ayacucho tanker will cover the route Venezuela-Singapore-China-Venezuela.

PDVSA plans to incorporate 3 more VLCC tankers into its fleet by YE:13.

The new PDVSA Suezmax Arauca tanker has oil capacity to transport 1 MMbbls.

PDVSA plans to incorporate 3 more Suezmax tankers into its fleet over the next 40 days.

PDVSA tanker fleet numbers 81, of which 54 are controlled by Venezuelan gov’t, allowing co. to control 66.67% of the Venezuelan oil fleet.

We have obtained financing from international banks, as well as banks from Japan and China. These are long term financing deals that are paid by the fleet. We expect to pay back these financing agreements within 5 or 6 years.

PDVSA President Rafael Ramirez on arrival of new tankers:

The Ayacucho arrived on 5.Oct.2013 and the others will arrive accordingly: Boyaca, Nov.2013; Carabobo, May.2014; and Junin, Oct.2014.

We will be looking to acquire four additional VLCCs.

We have tankers that are being constructed in Portugal, Brazil, China, Iran, Korea, in a way to diversify the supply of tankers.

The Suezmax Rio Arauca has capacity to transport 1.2 MMbbls, we are waiting on a total of 4 tankers

We are taking steps to guarantee our sovereignty in respect the transport of our crudes.

In 2012, we had a 33 tanker fleet and PDVSA just owned 12, or 36% was under PDVSA control. The remaining fleet of 21 was controlled by third parties who controlled 64%

We now have 81 tankers in our fleet, 52 controlled by PDVSA and 30 owned by PDVSA. Allowing PDVSA to have 66.6% of tanker fleet under its control.

The VLCCs conditioned to transport 2 MMbbls of Merey heavy oil to China. A typical VLCC has a dead weight of 300,000 tons, has a 2 MMbbl capacity, and can be loaded in 20 hours.

It is uneconomic for Venezuela to send oil to China using tankers with capacity of just 0.500 to 0.600 MMbbls, which translate into a $12/bbl for transport costs. In contrast, using tankers of 2 MMbbls we are able to reduce our transport costs to less than $3/bbl.

Our business plan for 2015 calls for PDVSA to have 52 tankers that are owned by PDVSA.

Our goal with China is to maintain average exports at 640 Mb/d in 2013. We have committed 200 Mb/d with financing schemes depending again on oil price.

We do not have problems in terms of tanker transportation, but our tanker plan encompasses renovation of tankers since we have tankers with more than 20 years of operation that need to be renovated.

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Rafael Ramirez Speech in Puerto La Cruz

(Energy Analytics Institute, Piero Stewart, 4.Oct.2013) – Venezuela’s Oil Minister President Rafael Ramirez spoke with journalist in Puerto La Cruz, Venezuela.

What follows are excerpts from the discussion.

Rafael Ramirez on the economic sector:

Ramirez: We have bonds that we are using to bring in food stuffs to guarantee supply to the Venezuelan people.

We will not use our dollars to create a parallel market. However, there are actors that are misusing these dollars to feed the speculative market.

We have to neutralize the elements that are conspiring against our economy in the parallel market that are creating distortions in Venezuela and of course affecting the people.

We will use our existing $600 million bonds to buy foodstuffs from Colombia. We will conduct whatever operation that is necessary to reestablish equilibrium in the area (of food distribution).

There are people in the private sector that have all the responsibility for everything that is happening to the Venezuelan economy. We will not use our dollars to create a parallel market, it would be a foolish move, right?

However, there are actors that are directing the use of the dollars that PDVSA is generating to supply this speculative sector. This is something that cannot be done by a maid or a student but economic actors that control large bolivar volumes and that continue to attack our economy. The actors working against the economy are different from those in the government.

On the petroleum sector:

Ramirez: We still need to finish work on the ICO pipeline system which will allow us to carry all of our gas from Eastern Venezuelan to Western Venezuela. The Northern Monagas region has become a great gas producer with 400 MMcf/d of gas.

The Faja did not have infrastructure to transport gas since the old associations said the Faja contained bitumen. Now that we are finding sufficient gas in the Faja coupled with gas from offshore, we will have sufficient gas to cover domestic demand as well as supply the Colombian market.

On gasoline/component imports from the U.S.:

Ramirez: We continue to import components to produce gasoline. It is a complex situation that we continue to evaluate.

We have taken control of the JV we had with Eni and we expanding the JV to produce the MTBE that we need. We continue to move forward with ethanol projects with the goal to mix 10% ethanol with our gasoline.

The Venezuelan driver consumes primarily 95 octane gasoline since the price between 95 and 91 octanes is the same, and under the perception that 95 octane is better for the automobiles.

On the Faja; companies leaving the Faja:

Ramirez: OPIC and PetroCanada were never in the Faja. Lukoil’s decision to leave Junin 6 was taken by the Russian consortium. It is a problem between the Russians. Rosneft President Igor Sechin has said his company wants to have a controlling or operating company in the consortium. We think it is a good decision since we would have one principal Russian voice in the JV.

PDVSA has to have a majority/controlling stake in the Faja projects because the transnational companies have their international strategies while PDVSA has a national strategy.

We have different options/offers to explore regarding Petronas’ 11% stake in Carabobo 1.

We are producing 3 MMb/d and working hard to increase production capacity.

The internal market in Venezuela is consuming 700 Mb/d, up due to increased demand for diesel. Venezuela is exporting 2.4 MMb/d, we want to send more gas to our electric sector which will allow them to switch from diesel to gas.

We plan to export at least 150 MMcf/d of gas to Colombia in July/June of 2014.

We are looking for alternatives so that early production materializes. Early production should approach 50,000 b/d from seven projects in 2013.

Junin 1: Sinopec agreement signed and companies working to constitute the JV and achieve production of 200,000 b/d. Junin 10: CNPC has agreed to participate in the JV and in the upgrader expansion with PDVSA. PDVSA has increased production at the project by 15,000 b/d in one year. We plan to expand the existing upgrader.

On the Abreu e Lima refinery project in Brazil:

We are still in discussions with Petrobras regarding the Abreu e Lima refinery project but this is a topic we will not discuss over a microphone. However, we want to be in the project.

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Q&A with Arthur Little’s Rodolfo Guzman

(Energy Analytics Institute, Pietro D. Pitts, 24.Sep.2013) – Arthur D. Little Partner Rodolfo Guzman spoke with Energy Analytics Institute in a brief interview from Houston, Texas. What follows are excerpts from the brief interview.

Regarding PDVSA’s potential departure from Abreu e Lima refinery project in Pernambuco, Brazil:

EAI: It appears PDVSA is close to leaving the Abreu e Lima refinery project in Brazil, is that a surprise to you: Why or why not?

Guzman: I wouldn’t be surprised if they leave the project. One reason is that PDVSA is financially not in a strong position to invest internationally; second, the execution capabilities of the company are limited.

The Abreu e Lima project was originally planned to receive heavy oil from Venezuela and Brazil. Now with all the pre-salt developments and future supply in Brazil, the dependence on Venezuela crudes for the refinery is lower. So, again, I am surprised that they may withdraw from the project.

PDVSA has a lot of priorities in Venezuela and the company’s refinery projects in the domestic market are moving forward very slowly. So why would the company commit to an international venture when they cannot progress with their own projects in Venezuela?

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Bolivia’s Nationalization of Oil and Gas

(Council on Foreign Relations, Carin Zissis, 12.May.2006) — In a region seen as turning leftward, forging alliances would seem a natural course of events. But Bolivian President Evo Morales’ decision to nationalize the oil and gas industry is exposing tensions, causing experts to say there is more diffusion than alliance-building in Latin America.

Introduction

On his hundredth day in office, Bolivian President Evo Morales moved to nationalize his nation’s oil and gas reserves, ordering the military to occupy Bolivia’s gas fields and giving foreign investors a six-month deadline to comply with demands or leave. The May 1 directive set off tensions in the region and beyond, particularly for foreign investors in Brazil, Spain, and Argentina. Morales’ nationalization agenda has been described as another chapter in Latin America’s turn to the left, and fears are rising that the Bolivian leader has fallen into the fold of Venezuela’s Hugo Chávez and Cuba’s Fidel Castro. But some experts emphasize there may be more infighting than cohesion overall in the region.

Why did Morales nationalize Bolivia’s hydrocarbon industry?

Morales, a former coca farmer and union leader, won a resounding victory in the December 2005 elections. As the Movement to Socialism (MAS) candidate, he campaigned in favor of nationalizing, among other sectors of the economy, the gas and oil industries with the cooperation of foreign investors. Experts say that, given such promises, the nationalization was no surprise. But Peter DeShazo, director of the Center for Strategic and International Studies’ Americas Program, says the move to occupy the gas fields with military forces lent a dramatic effect. “The confrontational nature of his move was certainly intended to get people’s attention,” he says, adding that Morales may be looking to garner votes in July elections for a constituent assembly that will redraft Bolivia’s constitution.

Nouriel Roubini, a professor of economics and international business at New York University, says one explanation for nationalization is ill will over encroachment on Bolivia’s territory by its neighbors. Since gaining independence in 1825, the Andean nation lost ocean access to Chile, as well as land to Brazil, Paraguay, and Peru. “There is this kind of historical resentment,” Roubini says, adding that Bolivians “are giving a slap in the face to Brazilians and Spaniards.” Morales echoed this sentiment at a May 11 summit of Latin American and European leaders, where he reaffirmed his energy-nationalization plans and signaled his government would seize large land holdings. Experts say this could also affect Brazil, whose farmers have major land holdings in Bolivia.

In spite of having the region’s second largest natural-gas reserves after Venezuela, Bolivia is among Latin America’s poorest nations. The landlocked country has also been marked by political instability; six presidents have held office in as many years, and one of them, Gonzalo “Goni” Sánchez de Lozada, was forced to resign in 2003 after protests against plans to export Bolivian gas turned violent. Among the free trader’s opponents was Morales, who said foreign investors received too much in gas-sale profits based on the hydrocarbons law in place at the time.

How will the nationalization plan work?

Morales’ May 1 decree states that foreign companies, which have invested almost $4 billion since Bolivia opened up its energy sector in the late 1990s, must hand majority control over to state-owned Yacimientos Petrolíferos Fiscales Bolivianos (YPFB). Firms have 180 days to renegotiate energy contracts with the Bolivian state, which experts say will likely lead to price increases. During that time, the companies which own the two largest oil fields will absorb a 32 percent hike (82 percent total) in royalties and taxes. Bolivia, which has 55 trillion cubic feet of natural gas, is expected to see a jump from $320 million to $780 million in annual oil-related revenues, and has installed new directors representing YPFB on the boards of foreign firms’ local subsidiaries. While negotiations occur, Bolivia will conduct an audit of the foreign companies. Morales recently warned foreign companies they will not be compensated if they have recovered their original investments.

Who stands to lose from the nationalization policy?

The firms with the largest holdings in Bolivia’s energy industry are the Spanish-Argentine venture Repsol YPF and Brazil’s Petrólio Brasileiro (Petrobras). Britain’s British Petroleum (BP) and France’s Total also have large investments. Repsol YPF has invested some $1.2 billion in Bolivia’s energy industry, and Argentina’s President Nestor Kirchner, whose country faces double-digit inflation rates, is concerned about rising gas prices jeopardizing Argentina’s economic recovery. But Brazil is under the greatest pressure if prices go up, as Bolivia provides it with about half of its gas. In the populous economic center of Sao Paolo that figure is closer to 75 percent. Petrobras has invested $1 billion in Bolivia’s natural-gas industry. Morales’ move has put Brazilian President Luiz Inácio Lula da Silva in a vulnerable position in the months leading up to his October reelection bid.

What are the reactions to Morales’ plan?

While foreign companies said they hope for cooperation, Repsol YPF has said it will act to protect its investments and take legal action if necessary. Petrobras has made similar threats and frozen investments. Experts say Bolivia needs investors such as Petrobras, which accounts for roughly 20 percent of the country’s gross domestic product (GDP) and 24 percent of its tax revenue. John Williamson, senior fellow at the Institute for International Economics, says Bolivia may see short-term gains but in the long term, it’s going to lead to less foreign investment. He also cautions that Morales’ move could cause divisions in the region.

Is Bolivia’s nationalization testing regional alliances?

Yes, say some experts. CFR Senior Fellow Julia Sweig says that Lula has been more silent in coming out against the nationalization than Spain’s President José Luis Rodríguez Zapatero because Lula—a former trade union leader like his Bolivian counterpart—is “sympathetic” to Morales’ intentions. Diego von Vacano, assistant professor of political science at Texas A&M University and a Bolivian national, says, “Lula wants to prevent a sort of face-off with Morales” because he “doesn’t want to destabilize the region.”

Yet, not all Latin American leaders who are leaning to the left are the same, experts say. “On one side, you have a number of administrations that are committed to moderate economic reform,” says Roubini. “On the other, you’ve had something of a backlash against the Washington Consensus [a set of liberal economic policies that Washington-based institutions urged Latin American countries to follow, including privatization, trade liberalization and fiscal discipline] and some emergence of populist leaders.” Among the latter group is Venezuela’s Chávez, an outspoken opponent of the Bush administration; DeShazo of CSIS calls Chávez Latin America’s “high priest” of economic nationalism.

What is Morales’ relationship with Chávez?

Just before the May 1 decree, Morales met with Chávez and Castro in Havana to sign a socialist trade agreement that made Morales a member of the Bolivarian Alternative for the Americas. The three are now calling it the “Axis of Good,” a pact originally signed by Chávez and Castro last year. Morales and Chávez threatened to pull out of the Andean Community if Colombia, Peru, and Ecuador sign free trade agreements with the United States. Castro and Chávez also said they would become Bolivia’s primary soybean importers. This plan may affect Brazil, because Morales has set a May 31 deadline for land redistribution in the Santa Cruz region, where Brazilian farmers grow more than a third of Bolivia’s soybeans and have invested heavily in land and agriculture.

But experts caution that it is not yet clear where Morales’ alliance falls. Sweig says “the embrace he’s getting from Chavez is getting harder and harder to resist,” but he also “understands that he has to function in a global context and not just an Andean one.” Sweig adds, “Bolivia is going to tack one way one day and one way the other.” There are also signs of infighting rather than a growth in alliances in the region. The Andean Community is not the only trading bloc with members threatening to bow out; in April, Uruguay warned it may leave Mercosur, the Southern Cone trading bloc, and suggested Paraguay is a partner on this. Williamson says the region “is more divided than I’ve ever seen it.” Sweig echoed this, saying, “I just don’t see the kind of diplomatic skill and institutional capacity to do alliance building. It’s not like the EU.”

What is the U.S. role in Bolivia and in the region?

Experts say the United States has paid less attention to Latin America after September 11, 2001, particularly as events have heated up in the Middle East. Meanwhile, Roubini says the situation in the region is “developing in such a way that is actually dangerous to U.S. interests.” According to Von Vacano, this period of crisis diplomacy between countries in the region would be a good time to become more engaged, and that the United States is “missing a chance to be a kind of broker, to get involved in South America without being heavy-handed.” Williamson says the United States should maintain an open hand to negotiate free trade agreements but “any U.S. influence is resented so much that it is counterproductive.” Sweig says the United States should tread carefully because intentions to influence outcomes can backfire. She points to Bolivia’s 2002 election, when the U.S. Ambassador Manuel Rocha urged Bolivians not to vote for Morales, who then surged in the polls and almost defeated Sánchez. The problem, Sweig says, “is when we say ’democracy,’ Latin Americans hear ’imperialism.’”

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